UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

or

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to ___________

Commission File Number: 001-34023

U.S. GEOTHERMAL INC.
(Exact Name of Registrant as Specified in Its Charter)

Delaware 84-1472231
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
   
390 E. Parkcenter Blvd., Suite 250  
Boise, Idaho 83706
(Address of Principal Executive Offices) (Zip Code)

208-424-1027
(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X]      No [   ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted

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pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [X]      No [   ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  [   ] Accelerated filer [   ]
Non-accelerated filer [   ]
(Do not check if a smaller reporting company)
Smaller reporting company [X]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [   ]      No [X]

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class Shares Outstanding as of August November 11, 2014
Common stock, par value $ 0.001 per share 106,325,260

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U.S. Geothermal Inc.
Form 10-Q
For the Third Quarter Ended September 30, 2014

INDEX

PART I – Financial Information  
     
Item 1 – Consolidated Financial Statements (Unaudited) 5
     
Consolidated Balance Sheet at September 30, 2014 and Consolidated Balance Sheet at December 31, 2013 6
     
Consolidated Statements of Operations – Three Months Ended and Nine Months Ended September 30, 2014 and 2013 7
     
Consolidated Statements of Cash Flow – Nine Months Ended September 30, 2014 and 2013 8
     
Consolidated Statement of Stockholders’ Equity – Year Ended December 31, 2013 and Nine Months Ended September 30, 2014 9
     
  Notes to Consolidated Financial Statements 10
     
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations 37
  -        General Background and Discussion 38
  -        Operating Results 44
  -        Off Balance Sheet Arrangements 56
  -        Liquidity and Capital Resources 54
  -        Potential Acquisitions 59
  -        Critical Accounting Policies 59
     
Item 3 – Quantitative and Qualitative Disclosures about Market Risk 59
     
Item 4 - Controls and Procedures 60
     
PART II – Other Information  
     
Item 1 - Legal Proceedings 61
     
Item 1A - Risk Factors 61
     
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds 61
     
Item 3 - Defaults Upon Senior Securities 61
     
Item 4 – Mine Safety Disclosures 61
     
Item 5 - Other Information 61
     
Item 6 - Exhibits 61

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Part I - Financial Information

Item 1 - Financial Statements

The financial statements included herein have been prepared by U.S. Geothermal Inc. (the “Company”), without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles may have been condensed or omitted. However, in the opinion of management, all adjustments (which include only normal recurring accruals) necessary to present fairly the financial position and results of operations for the periods presented have been made. These financial statements should be read in conjunction with the accompanying notes, and with the audited financial statements and notes to the financial statements included in the Company’s report on Form 10-K for the year ended December 31, 2013. The results of operations for the nine months ended September 30, 2014 are not necessarily indicative of the results to be expected for the year ending December 31, 2014.

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U.S. GEOTHERMAL INC.
________

Consolidated Financial Statements
(Unaudited)
September 30, 2014

 

 

 


U.S. GEOTHERMAL INC.
CONSOLIDATED BALANCE SHEETS

    (Unaudited)        
    September 30, 2014     December 31, 2013  
             
ASSETS            
             
Current:            
     Cash and cash equivalents (note 2) $  10,695,122   $  28,736,934  
     Restricted cash and bonds (note 3)   2,251,707     3,081,020  
     Trade accounts receivable   2,518,260     4,106,806  
     Other current assets   1,363,419     1,079,262  
             Total current assets   16,828,508     37,004,022  
             
Investment in equity securities (note 4)   -     42,174  
Costs on acquisition   187,794     -  
Restricted cash and bond reserves (note 3)   18,692,614     18,815,145  
Property, plant and equipment, net of accumulated depreciation (note 5)   167,990,151     161,583,938  
Intangible assets, net of accumulated amortization (note 6)   15,462,626     15,320,018  
             
                          Total assets $  219,161,693   $  232,765,297  
             
LIABILITIES AND STOCKHOLDERS’ EQUITY            
             
Current Liabilities:            
     Accounts payable and accrued liabilities $  1,305,784   $  1,626,687  
     Related party accounts payable   11,473     3,089  
     Current portion of capital lease obligations (note 8)   33,227     48,118  
     Current portion of notes payable (note 9)   4,283,575     4,127,170  
             Total current liabilities   5,634,059     5,805,064  
             
Long-term Liabilities:            
     Long-term portion of capital lease obligations (note 8)   -     20,921  
     Asset retirement obligations (note 14)   1,400,000     -  
     Notes payable, less current portion (note 9)   94,760,130     99,226,423  
             Total long-term liabilities   96,160,130     99,247,344  
             
                          Total liabilities   101,794,189     105,052,408  
             
Commitments and Contingencies (note 14)   -     -  
             
STOCKHOLDERS’ EQUITY            
Capital stock (authorized: 250,000,000 common shares with a $0.001 par value; issued and outstanding shares at September 30, 2014 and December 31, 2013 were: 106,325,260 and 102,094,542; respectively)   106,325     102,094  
Additional paid-in capital   103,110,665     100,381,207  
Accumulated other comprehensive loss   -     (27,321 )
Accumulated deficit   (30,630,183 )   (30,898,571 )
    72,586,807     69,557,409  
             
Non-controlling interests (note 15)   44,780,697     58,155,480  
             Total stockholders’ equity   117,367,504     127,712,889  
             
                             Total liabilities and stockholders’ equity $  219,161,693   $  232,765,297  

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

    (Unaudited)     (Unaudited)  
    For the Three Months Ended     For the Nine Months Ended  
    September 30,     September 30,  
    2014     2013     2014     2013  
                         
Plant Revenues:                        
       Energy sales $  6,649,120   $  5,667,070   $  20,810,254   $  17,542,568  
       Energy credit sales   87,885     93,425     274,590     277,992  
Total plant operating revenues   6,737,005     5,760,495     21,084,844     17,820,560  
                         
Plant Expenses:                        
       Plant production expenses   2,246,034     1,730,493     7,115,530     5,365,456  
       Depreciation and amortization   1,551,299     1,568,650     4,674,605     4,878,892  
Total plant operating expenses   3,797,333     3,299,143     11,790,135     10,244,348  
                         
Net Income from Plant Operations   2,939,672     2,461,352     9,294,709     7,576,212  
                         
Expenses (Income):                        
       Corporate administration   216,386     240,761     808,489     737,630  
       Professional and management fees   186,849     248,861     754,796     980,211  
       Salaries and wages   400,950     537,482     1,473,006     1,655,624  
       Stock based compensation   321,306     307,408     1,098,771     571,160  
       Travel and promotion   60,362     48,940     160,356     168,154  
       Exploration costs   27,221     (67,211 )   70,709     509,174  
       Interest expense   1,089,686     985,654     3,079,415     2,589,825  
       Other (income) expenses   (58,905 )   (26,741 )   (85,412 )   (90,217 )
Total expenses (income)   2,243,855     2,275,154     7,360,130     7,121,561  
                         
Net Income Before Income Tax Expense   695,817     186,198     1,934,579     454,651  
                         
Net Income Tax Expense (note 7):                        
       Income taxes   266,000     71,000     739,000     174,000  
       Effect of net deferred tax assets   (266,000 )   (71,000 )   (739,000 )   (174,000 )
Net income tax expense   -     -     -     -  
                         
Net Income   695,817     186,198     1,934,579     454,651  
                         
         Net income attributable to the non-controlling interests   (614,037 )   (214,335 )   (1,666,191 )   (470,624 )
                         
Net Income (Loss) Attributable to U.S. Geothermal Inc.   81,780     (28,137 )   268,388     (15,973 )
                         
Other Comprehensive Income (Loss):                        
         Unrealized income (loss) on investment in 
                  equity securities
  -     (1,372 )   27,321     (21,919 )
                         
Comprehensive Income (Loss) Attributable to U.S. Geothermal Inc. $  81,780   $  (29,509 ) $  295,709   $  (37,892 )
                         
Basic Net Income (Loss) Per Share Attributable to U.S. Geothermal Inc. $  0.00   $  (0.00 ) $  0.00   $  (0.00 )
Diluted Net Income (Loss) Per Share Attributable to U.S. Geothermal Inc. $  0.00   $  (0.00 ) $  0.00   $  (0.00 )
                         
Weighted Average Number of Shares Outstanding for Basic Calculations   104,587,598     102,044,300     103,541,220     101,694,542  
Weighted Average Number of Shares, Stock Options and Warrants Outstanding for Diluted Calculations   126,154,705     102,044,300     125,941,413     101,694,542  

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S. GEOTHERMAL INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

    (Unaudited)  
    For the Nine Months Ended September 30,  
    2014     2013  
             
Operating Activities:            
Net Income $  1,934,579   $  454,651  
Adjustments to reconcile net income to total cash provided by operating activities:        
           Depreciation and amortization   4,772,192     4,969,582  
           Stock based compensation   1,098,771     571,160  
           Stock based officer bonus   -     100,000  
           Gain on software refund   (13,239 )   -  
           Loss on sale of securities   27,967     -  
 Net changes in:            
           Trade accounts receivable, operating   1,588,546     1,305,389  
           Accounts payable and accrued liabilities   (1,320,909 )   (582,841 )
           Prepaid expenses and other   (284,157 )   (144,526 )
                Total cash provided by operating activities   7,803,750     6,673,415  
             
Investing Activities:            
     Purchases of property, plant and equipment   (2,874,315 )   (9,691,268 )
     Acquisition of subsidiaries (note 16)   (6,782,446 )   -  
     Costs related to acquisition   (187,794 )   -  
     Proceeds from ITC cash grants receivable   -     33,800,784  
     Proceeds from sale of equities held for investment   41,528     -  
     Proceeds from software refund   31,120     -  
     Release (funding) of restricted cash reserves and bonds   1,051,844     (12,724,097 )
           Total cash provided (used) by investing activities   (8,720,063 )   11,385,419  
             
Financing Activities:            
     Issuance of share capital   1,634,918     -  
     Contributions from non-controlling interest   7,360     7,460  
     Distributions to non-controlling interest   (15,048,334 )   (89,221 )
     Principal payments on convertible debt obligations   -     (2,125,000 )
     Principal payments on notes payable and other obligations   (3,683,631 )   (4,602,607 )
     Principal payments on capital leases   (35,812 )   (33,696 )
           Total cash used by financing activities   (17,125,499 )   (6,843,064 )
             
Increase (Decrease) in Cash and Cash Equivalents   (18,041,812 )   11,215,770  
             
Cash and Cash Equivalents, Beginning of Period   28,736,934     12,908,779  
             
Cash and Cash Equivalents, End of Period $  10,695,122   $  24,124,549  
             
Supplemental Disclosures:            
Non-cash investing and financing activities:            
     Purchase of property and equipment on account $  425,529   $  1,066,271  
     Purchase of property and equipment with notes payable   71,245     -  
     Construction and development paid directly with construction loans   -     2,355,316  
     Property and equipment costs reduced by settlement agreements   -     7,387,658  
     Grants receivable used to decrease construction costs   -     1,719,216  
             
Other Items:            
     Interest paid   3,538,629     4,365,949  

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S. GEOTHERMALINC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
For the Nine Months Ended September 30, 2014 and the Year Ended December 31, 2013

                Additional           Accumulated     Non-        
    Number of     Common     Paid-In     Accumulated     Comprehensive     controlling        
    Shares     Shares     Capital     Deficit     Income (Loss)     Interest     Totals  
                                           
                                           
Balance at December 31, 2012   101,516,764   $  101,516   $  99,524,850   $  (32,845,150 ) $  (3,944 ) $  56,081,198   $  122,858,470  
                                           
Non-controlling equity contribution from
   Gerlach Green Energy, LLC
  -     -     -     -     -     7,460     7,460  
Distributions to non-controlling interest entity   -     -     -     -     -     (117,248 )   (117,248 )
Stock issued under terms of employment
   agreement
  577,778     578     99,422     -     -     -     100,000  
Stock compensation   -     -     756,935     -     -     -     756,935  
Unrealized loss on investment   -     -     -     -     (23,377 )   -     (23,377 )
Net income   -     -     -     1,946,579     -     2,184,070     4,130,649  
                                           
Balance at December 31, 2013   102,094,542     102,094     100,381,207     (30,898,571 )   (27,321 )   58,155,480     127,712,889  
                                           
Distributions to non-controlling interest
   entities (note 15)
  -     -     -     -     -     (15,048,334 )   (15,048,334 )
Non-controlling equity contribution from
   Gerlach Green Energy, LLC
  -     -     -     -     -     7,360     7,360  
Stock issued by the exercise of employee
   stock options
  1,077,000     1,077     336,544     -     -     -     337,621  
Stock issued by the exercise of stock
   purchase warrants
  2,594,596     2,595     1,294,703     -     -     -     1,297,298  
Stock compensation   559,122     559     1,098,211     -     -     -     1,098,770  
Unrealized loss and reclassification to
   net income
  -     -     -     -     27,321     -     27,321  
Net income   -     -     -     268,388     -     1,666,191     1,934,579  
                                           
Balance at September 30, 2014 - unaudited   106,325,260   $  106,325   $  103,110,665   $  (30,630,183 ) $  -   $  44,780,697   $  117,367,504  

The accompanying notes are an integral part of these interim consolidated financial statements.
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U.S. GEOTHERMAL INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Unaudited
September 30, 2014

NOTE 1 - ORGANIZATION AND DESCRIPTION OF BUSINESS

U.S. Geothermal Inc. was incorporated on March 10, 2000 in the State of Delaware. U.S. Geothermal Inc. – Idaho was formed in February 2002, and is the primary subsidiary through which the Company conducts its operations. The Company constructs, manages and operates power plants that utilize geothermal resources to produce energy. The Company’s operations have been, primarily, focused in the Western United States of America.

Basis of Presentation

These unaudited interim consolidated financial statements of the Company and its subsidiaries have been prepared in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). Such rules and regulations allow the omission of certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America, so long as such omissions do not render the financial statements misleading. Certain prior period amounts have been reclassified to conform to the current period presentation.

In the opinion of management, these financial statements reflect all adjustments that are necessary for a fair statement of the results for the periods presented. All adjustments were of a normal recurring nature. These interim financial statements should be read in conjunction with the annual financial statements of the Company included in its Report on Form 10-K.

The Company consolidates subsidiaries that it controls (more-than-50% owned) and entities over which control is achieved through means other than voting rights. These consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, as well as three controlling interests. The accounts of the following companies are consolidated in these financial statements:

  i)

U.S. Geothermal Inc. (incorporated in the State of Delaware);

  ii)

U.S. Geothermal Inc. (incorporated in the State of Idaho);

  iii)

U.S. Geothermal Services, LLC (organized in the State of Delaware);

  iv)

Nevada USG Holdings, LLC (organized in the State of Delaware);

  v)

USG Nevada LLC (organized in the State of Delaware);

  vi)

Nevada North USG Holdings, LLC (organized in the State of Delaware);

  vii)

USG Nevada North, LLC (organized in the State of Delaware);

  viii)

Oregon USG Holdings, LLC (organized in the State of Delaware);

  ix)

USG Oregon LLC (organized in the State of Delaware);

  x)

Raft River Energy I LLC (organized in the State of Delaware);

  xi)

Gerlach Geothermal LLC (organized in the State of Delaware);

  xii)

USG Gerlach LLC (organized in the State of Delaware);

  xiii)

U.S. Geothermal Guatemala, S.A. (organized in Guatemala);

  xiv)

Geysers USG Holdings Inc. (incorporated in the State of Delaware);

  xv)

Western GeoPower, Inc. (incorporated in the State of California);

  xvi)

Etoile Holdings Inc. (incorporated in the Bahamas);

  xvii)

Mayacamas Energy LLC (organized in the State of California);

  xviii)

Skyline Geothermal LLC (organized in the State of Delaware);

  xix)

Skyline Geothermal Holding, Inc. (incorporated in the State of Delaware); and

  xx)

USG Cresent Valley Inc. (incorporated in Delaware).

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All intercompany transactions are eliminated upon consolidation.

In cases where the Company owns a majority interest in an entity but does not own 100% of the interest in the entity, it recognizes a non-controlling interest attributed to the interest controlled by outside third parties. The Company will recognize 100% of the assets and liabilities of the entity, and disclose the non-controlling interest. The statements of operations will consolidate the subsidiary’s full operations, and will separately disclose the elimination of the non-controlling interest’s allocation of profits and losses.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The following are summarized accounting policies considered to be significant by the Company’s management:

Accounting Method

The Company’s consolidated financial statements are prepared using the accrual basis of accounting in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) and have been consistently applied in the preparation of the consolidated financial statements.

Use of Estimates

The preparation of consolidated financial statements in accordance with generally accepted accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities known to exist as of the date the consolidated financial statements are published, and the reported amounts of revenues and expenses during the reporting period. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of the Company’s consolidated financial statements; accordingly, it is possible that the actual results could differ from these estimates and assumptions and could have a material effect on the reported amounts of the Company’s consolidated financial position and consolidated results of operations.

Cash and Cash Equivalents

The Company considers all unrestricted cash, short-term deposits, and other investments with original maturities of no more than ninety days when acquired to be cash and cash equivalents for the purposes of the statement of cash flows. Under the Loan Guarantee Agreement at Neal Hot Springs with the Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank subject to certain procedural restrictions on the use of the funds. The waterfall of funds out of the Revenue account is processed semi-annually. At September 30, 2014, $704,000 in USG Oregon LLC funds were deposited at PNC Bank and $278,000 in Oregon USG Holdings LLC funds were deposited at Umpqua Bank, and were unavailable for immediate corporate needs. Discussion regarding restricted cash is included in Note 3.

Accounts Receivable Allowance for Doubtful Accounts

Trade Accounts Receivable
Management estimates the amount of trade accounts receivable that may not be collectible and records an allowance for doubtful accounts. The allowance is an estimate based upon aging of receivable balances, historical collection experience, and the periodic credit evaluations of our customers’ financial condition. Receivable balances are written off when we determine that the balance is uncollectible. As of September 30, 2014 and December 31, 2013, there were no balances that were over 90 days past due and no balance in allowance for doubtful accounts was recognized.

-11-


Grant Accounts Receivable
For receivables from grants from Federal or State agencies, the Company records the receivable amounts net of the funds expected to be received. Therefore, no allowance accounts are considered to be necessary for receivables from grants at September 30, 2014 and December 31, 2013.

Concentration of Credit Risk

The Company’s cash and cash equivalents, including restricted cash, consisted of commercial bank deposits, money market accounts, and petty cash. Cash deposits are held in commercial banks in Boise, Idaho and Portland, Oregon. Deposits are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 per legal entity. At September 30, 2014, the Company’s total cash balance, excluding money market funds, was $4,187,430, and bank deposits amounted to $4,453,398. The primary difference was due to outstanding checks and deposits. Of the bank deposits, $2,999,632 was not covered by or was in excess of FDIC insurance guaranteed limits. At September 30, 2014, the Company’s money market funds invested in government backed securities totaled $27,448,313 and were not subject to deposit insurance.

Equity Securities

The Company determines the appropriate classification of marketable securities at the time of purchase and reevaluates this designation as of each balance sheet date. The Company classifies these securities as either held-to-maturity, trading, or available-for-sale. All marketable securities and restricted investments were classified as available-for-sale securities. The Company classifies its investments as “available for sale” because it does not intend to actively buy and sell for short-term profits. The Company's investments are subject to market risk, primarily interest rate and credit risk. The fair value of investments is determined using observable or quoted market prices for those securities.

Available-for-sale securities are carried at fair value, with unrealized gains and losses included as a component of accumulated other comprehensive income (loss). Realized gains and losses, declines in value judged to be other than temporary and interest on available-for-sale securities are included in net income. The cost of securities sold is based on the specific identification method.

Property, Plant and Equipment

Property, plant and equipment, including assets under capital lease, are recorded at historical cost. Costs of acquisition of geothermal properties are capitalized in the period of acquisition. Major improvements that significantly increase the useful lives and/or capabilities of the assets are capitalized. A primary factor in determining whether to capitalize construction type costs is the stage of the potential project’s development. Once a project is determined to be commercially viable, all costs directly associated with the development and construction of the project are capitalized. Until that time, all development costs are expensed. A commercially viable project will have, among other factors, a reservoir discovery well or other significant geothermal surface anomaly, a power transmission path that is identified and available, and an electricity off-taker identified. A valid reservoir discovery is generally defined when a test well has been substantially completed that indicates the presence of a geothermal reservoir that has a high probability of possessing the necessary temperatures, permeability, and flow rates. After a valid discovery has been made, the project enters the development stage. Generally, all costs incurred during the development stage are capitalized and tracked on an individual project basis. If a geothermal project is abandoned, the associated costs that have been capitalized are charged to expense in the year of abandonment. Expenditures for repairs and maintenance are charged to expense as incurred. Interest costs incurred during the construction period of defined major projects from debt that is specifically incurred for those projects are capitalized. Funds received from grants associated with capital projects reduce the cost of the asset directly associated with the individual grants. The offset of the cost of the asset associated with grant proceeds is recorded in the period when the requirements of the grant are substantially complete and the amount can be reasonably estimated.

-12-


Direct labor costs, incurred for specific major projects expected to have long-term benefits will be capitalized. Direct labor costs subject to capitalization include employee salaries, as well as, related payroll taxes and benefits. With respect to the allocation of salaries to projects, salaries are allocated based on the percentage of hours that our key managers, engineers and scientists work on each project and are invoiced to the project each month. These individuals track their time worked at each project. Major projects are, generally, defined as projects expected to exceed $500,000. Direct labor includes all of the time incurred by employees directly involved with construction and development activities. General and/or indirect management time and time spent evaluating the feasibility of potential projects are expensed when incurred. Employee training time is expensed when incurred.

Depreciation is calculated on a straight-line basis over the estimated useful life of the asset. Where appropriate, terms of property rights and revenue contracts can influence the determination of estimated useful lives. Estimated useful lives in years by major asset categories are summarized as follows:

    Estimated Useful
Asset Categories   Lives in Years
     
Furniture, vehicle and other equipment   3 to 5
Power plant, buildings and improvements   3 to 30
Wells   30
Well pumps and components   5 to 15
Pipelines   30
Transmission lines   30

Intangible Assets

All costs directly associated with the acquisition of geothermal and surface water rights are capitalized as intangible assets. These costs are amortized over their estimated utilization period. There are several factors that influence the estimated utilization periods as well as underlying fair value that include, but are not limited to, the following:

  - contractual expiration terms of the right,
  - contractual terms of an associated revenue contract (i.e., PPAs),
  - compliance with utilization and other requirements, and
  - hierarchy of other right holders who share the same resource.

Currently, amortization expense is being calculated on a straight-line basis over an estimated utilization period of 30 years for assets placed in service. If an intangible water or geothermal right is forfeited or otherwise lost, the remaining unamortized costs are expensed in the period of forfeiture. An impaired right is reduced to its estimated fair market value in the year the impairment is realized. Costs incurred that extend the term of an intangible right are capitalized and amortized over the new estimated period of utilization.

Impairment of Long-Lived Assets

The Company evaluates its long-term assets annually for impairment and when circumstances/events occur that may impact the fair value of the assets. An impairment loss would be recognized if the carrying amount of a capitalized asset is not recoverable and exceeds its fair value. The most recent assessment was performed based upon financial conditions and assumptions as of December 31, 2013, and there have not been any significant changes in financial conditions and assumptions subsequent to that assessment date. Management believes that there have not been any circumstances that have warranted the recognition of losses due to the impairment of long-lived assets.

-13-


Stock Options Granted to Employees and Non-employees

The Company follows financial accounting standards that require the measurement of the value of employee services received in exchange for an award of an equity instrument based on the grant-date fair value of the award. For employees, directors and officers, the fair value of the awards are expensed over the vesting period. The current vesting period for all such options is eighteen months.

Non-employee stock-based compensation is granted at the Board of Director’s discretion to reward select consultants for exceptional performance. Prior to issuance of the awards, the Company was not under any obligation to issue the stock options. Subsequent to the award, the recipient was not obligated to perform any services. Therefore, the fair value of these options was expensed on the grant date, which was also the measurement date.

Under the fair value recognition provisions, share-based compensation cost is measured at the grant date based on the value of the award and is recognized as expense over the vesting period. Determining the fair value of share-based awards at the grant date requires judgment. In addition, judgment is also required in estimating the amount of share-based awards that are expected to be forfeited. If actual results differ significantly from these estimates, stock-based compensation expense and our results of operations could be materially impacted.

Stock Based Compensation Granted to Employees

The Company recognizes the value of common stock granted to employees and directors over the periods in which the services are received. The value of those services is based upon the estimated fair value of the common stock to be awarded. Estimated fair value is adjusted each reporting period. At the end of each vesting period, estimated fair value is adjusted to fair market value. The adjustment is reflected in the reporting period in which the vesting occurs.

Earnings (Losses) Per Share

The Company follows financial accounting standards, which provides for calculation of "basic" and "diluted" earnings (losses) per share. Basic earnings per share includes no dilution and is computed by dividing net income available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of an entity similar to fully diluted earnings per share. Both basic and diluted were presented for the calculation of the income per share for the periods that reported income. Stock equivalents were not included in the calculation for the periods that reported losses since their inclusion would be considered anti-dilutive. Total common stock equivalents on a fully diluted basis at September 30, 2014 and December 31, 2013 were 126,091,335 and 124,494,963; respectively.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, trade account and other receivables, refundable tax credits, and accounts payable and accrued liabilities. Unless otherwise noted, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise noted.

The Company’s functional currency is the U.S. dollar. Monetary items are converted into U.S. dollars at the rate prevailing at the balance sheet date. Resulting gains and losses are generally included in determining net income for the period in which exchange rates change.

-14-


Revenue

Revenue Recognition

Energy Sales
The energy sales revenue is recognized when the electrical power generated by the Company’s power plants is delivered to the customer who is reasonably assured to be able to pay under the terms defined by the Power Purchase Agreements (“PPAs”).

Renewable Energy Credits (“RECs”)
Currently, the Company operates three plants that produce renewable energy that creates a right to a REC. The Company earns one REC for each megawatt hour produced from the geothermal power plant. The Company considers the RECs to be an inventory item held for sale, and outputs that are an economic benefit obtained directly through the operation of the plants. The Company does not currently hold any RECs for our own use. Revenues from RECs sales are recognized when the Company has met the terms and conditions of certain energy sales agreements with a financially capable buyer. At Raft River Energy I LLC, each REC is certified by the Western Electric Coordinating Council and sold under a REC Purchase and Sales Agreement to Holy Cross Energy. At San Emidio and Neal Hot Springs, the RECs are owned by our customer and are bundled with energy sales. At all three plants, title for the RECs pass during the same month as energy sales. As a result, costs associated with the sale of RECs are not segregated on the statement of operations.

Revenue Source
All of the Company’s operating revenues (energy sales and energy credit sales) originate from energy production from its interests in geothermal power plants located in the states of Idaho, Oregon and Nevada.

Asset Retirement Obligations

The Company records the fair value of estimated asset retirement obligations (“AROs”) associated with tangible long-lived assets in the period incurred or acquired. AROs are legal obligations to settle under existing or enacted law, statue, or contract. The value of these obligations are originally based upon discounted cash flow estimates and are accreted to full value over time through charges to operations. Costs associated with future conditions are recognized as AROs in the period the condition occurs or is known to the Company. Generally, costs associated with AROs are earthwork, revegetation, well capping, and structure removal necessary to return the sites to their original conditions.

Reclassification

Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. These reclassifications had no effect on reported losses, total assets, or stockholders’ equity as previously reported.

-15-


Recent Accounting Pronouncements

Management has considered all recent accounting pronouncements. The following pronouncements were deemed applicable to our financial statements:

Stock Compensation
In June 2014, FASB issued Accounting Standards Update No. 2014-12 (“Update 2014-12”), Compensation-Stock Compensation, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period (Topic 718). Update 2014-12 provides guidance on how to account for share-based payment awards that require a specific performance target to be achieved in order for the employees to become eligible to vest in the awards. Update 2014-12 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Management is still evaluating the applicability and possible impact this update may have on the accounting treatment and its financial statement presentation.

Presentation of Property, Plant and Equipment
In April 2014, FASB issued Accounting Standards Update No. 2014-08 (“Update 2014-08”), Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360), Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. Update 2014-08 provides guidance to address the issues surrounding the reporting of discontinued operations and enhance the convergence of the FASB’s and the International Accounting Standard Board’s reporting requirements for discontinued operations. Update 2014-08 is effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Management is still evaluating the applicability and possible impact this update may have on the accounting treatment and its financial statement presentation.

-16-


NOTE 3 – RESTRICTED CASH AND BOND RESERVES

Under the terms of the loan agreements with the Department of Energy and Prudential Capital Group, various bond and cash reserves are required to provide assurances that the power plants will have the necessary funds to maintain expected operations and meet loan payment obligations. Restricted cash balances and bond reserves are summarized as follows:

Current restricted cash and bond reserves:

      September 30,     December 31,  
Restricting Entities/Purpose     2014     2013  
Idaho Department of Water Resources, Geothermal Well Bond   $  260,000   $  260,000  
Bureau of Land Management, Geothermal Lease Bond- Gerlach     10,000     10,000  
State of Nevada Division of Minerals, Statewide Drilling Bond     50,000     50,000  
Bureau of Land Management, Geothermal Lease Bonds- USG Nevada     150,000     150,000  
Oregon Department of Geology and Mineral Industries, Mineral Land and Reclamation Program     400,000     400,000  
Prudential Capital Group, Cash Reserves     420,981     19,848  
U.S. Department of Energy, Debt Service Reserve     860,726     2,191,172  
State of California Division of Oil, Gas and Geothermal Resources, Well Cash Bond     100,000     -  
               
    $  2,251,707   $  3,081,020  

Long-term restricted cash and bond reserves:

      September 30,     December 31,  
Restricting Entities/Purpose     2014     2013  
Nevada Energy, PPA Security Bond   $  1,468,898   $  1,468,898  
Prudential Capital Group, Debt Service Reserves     1,594,520     1,594,437  
Prudential Capital Group, Maintenance Reserves     580,177     751,183  
Prudential Capital Group, Well Reserves     212,289     53,072  
U.S. Department of Energy, Operations Reserves     270,000     270,000  
U.S. Department of Energy, Debt Service Reserves     2,582,187     2,668,179  
U.S. Department of Energy, Short Term Well Field Reserves     4,504,420     4,501,191  
U.S. Department of Energy, Long-Term Well Field Reserves     4,761,156     4,507,391  
U.S. Department of Energy, Capital Expenditure Reserves     2,718,967     3,000,794  
               
    $  18,692,614   $  18,815,145  

The well bonding requirements ensure that the Company has sufficient financial resources to construct, operate and maintain geothermal wells while safeguarding subsurface, surface and atmospheric resources from unreasonable degradation, and to protect ground water aquifers and surface water sources from contamination. Other future costs of environmental remediation cannot be reasonably estimated and have not been recorded. The debt service reserves are required to provide assurance that the Company will have sufficient funds to meet its debt payment obligations for the terms specified by the loan agreements. The maintenance and capital expenditure reserves are required by the lending entities to ensure that funds are available to acquire and maintain critical components of power plants and related supporting structures to enable the plants to operate according to expectations. Except for the PPA Security Bond, all of the restricted funds consisted of cash deposits or money market accounts held in commercial banks. Portions of the cash deposits are subject to FDIC insurance. See note 2 for details. The PPA Security Bond is held by the power purchaser. All of the reserve accounts were considered to be fully funded at September 30, 2014 and December 31, 2013. As described in note 16, the Geyser’s acquisition included a short term well bond of $100,000 at September 30, 2014.

-17-


NOTE 4 – INVESTMENT IN EQUITY SECURITIES

During the quarter ended March 31, 2014, all of the Company’s holdings of equity securities (150,000 shares of Alterra Power Corp, a publicly traded renewable energy company) were sold for $41,528, which resulted in a realized loss of $27,967. The net change of $27,321 was reclassified from other comprehensive income to net income as a result of the sale.

NOTE 5 - PROPERTY, PLANT AND EQUIPMENT

During the quarter ended September 30, 2014, the Company incurred well drilling costs that exceeded $942,000 and other development costs that exceeded $545,000 for the San Emidio projects (located in Northwestern Nevada). Two Phase II San Emidio exploration wells were started and completed during the current quarter. A new production well was completed and connected to the existing Phase I power plant. This well is still being evaluated, and has not been transferred into plant operations. On August 21, 2014, the Company purchased three trucks for the plants that totaled $118,245.

During the quarter ended June 30, 2014, the Company acquired a group of companies that included long-term assets that totaled $7.74 million (land of $1.6 million, well and drilling construction in progress of $6.14 million). See note 16 for details. The Company continued with development activities for Phase II San Emidio and the Guatemala projects. For Phase II San Emidio, over $206,000 was incurred for well drilling and permitting. At Guatemala, over $353,000 was incurred on temperature gradient wells and plant facilities. Costs of approximately $74,800 were incurred at Neal Hot Springs, Oregon on a bridge.

During the quarter ended March 31, 2014, the Company continued with development activities for Phase II San Emidio, Nevada and the Guatemala projects. For Phase II San Emidio, over $81,000 was incurred on a seismic study, well pad permitting, and well drilling, At Guatemala, over $395,000 was incurred on temperature gradient wells.

Property, plant and equipment, at cost, are summarized as follows:

    September 30,     December 31,  
    2014     2013  
Land $  3,207,025   $  1,603,509  
Power production plant   162,076,367     161,868,687  
Grant proceeds for power plants   (52,965,236 )   (52,965,236 )
Wells   67,621,167     67,620,661  
Grant proceeds for wells   (3,464,555 )   (3,464,555 )
Furniture and equipment   1,762,280     1,462,312  
    178,237,048     176,125,378  
             
           Less: accumulated depreciation   (25,518,632 )   (20,895,943 )
    152,718,416     155,229,435  
Construction in progress   15,271,735     6,354,503  
             
  $  167,990,151   $  161,583,938  

-18-


Depreciation expense was charged to plant operations and general expenses for the following periods:

    September 30,  
    2014     2013  
             
Three months ended $  1,538,721   $  1,536,042  
Nine months ended   4,635,928     4,782,539  

Changes in Construction in Progress are summarized as follows:

    For the Nine     For the Year  
    Months Ended     Ended December  
    September 30, 2014     31, 2013  
Beginning balances $  6,354,503   $  2,877,994  
     Development/construction   2,717,174     3,694,978  
     Grant reimbursements and rebates   -     (33,325 )
     Acquisition (note 16)   6,200,058     -  
     Transfers into production   -     (185,144 )
Ending balances $  15,271,735   $  6,354,503  

Construction in Progress, at cost, consisting of the following projects/assets by location are as follows:

    September 30,     December 31,  
    2014     2013  
Raft River, Idaho:            
         Unit II, power plant, substation and transmission lines $  750,493   $  750,493  
         Unit II, well construction   2,127,355     2,121,502  
    2,877,848     2,871,995  
San Emidio, Nevada:            
         Unit II, power plant, substation and transmission lines   383,536     3,910  
         Unit II, well construction   3,154,914     1,753,299  
    3,538,450     1,757,209  
Neal Hot Springs, Oregon:            
Power plant and facilities   450     -  
             
The Geysers, California (note 16):            
       Power plant and facilities   137,225     -  
       Well construction   6,139,421     -  
    6,276,646     -  
El Ceibillo, Republic of Guatemala:            
       Well Construction   2,569,841     1,725,299  
       Plant and facilities   8,500     -  
    2,578,341     1,725,299  
             
  $  15,271,735   $  6,354,503  

-19-


NOTE 6 – INTANGIBLE ASSETS

During the quarter ended June 30, 2014, the Company acquired a group of companies that included geothermal water rights located at The Geysers in Northern California that amounted to $278,872 (see note 16 for details).

Intangible assets, at cost, are summarized by project location as follows:

    September 30,     December 31,  
    2014     2013  
In operation:            
     Neal Hot Springs, Oregon:            
             Geothermal water and mineral rights $  625,337   $  625,337  
     San Emidio, Nevada:            
             Geothermal water and mineral rights   4,825,220     4,825,220  
     Less: accumulated amortization   (1,072,013 )   (935,749 )
    4,378,544     4,514,808  
Inactive:            
     Raft River, Idaho:            
             Surface water rights   146,343     146,343  
             Geothermal water and mineral rights   1,251,540     1,251,540  
             
     Granite Creek, Nevada:            
             Geothermal water and mineral rights   451,299     451,299  
             
     Guatemala City, Guatemala:            
             Geothermal water and mineral rights   625,000     625,000  
             
     Gerlach, Nevada:            
             Geothermal water and mineral rights   997,000     997,000  
             
     The Geysers, California:            
             Geothermal water rights (note 16)   278,872     -  
             
     San Emidio, Nevada:            
             Surface water rights   4,323,520     4,323,520  
             Geothermal water and mineral rights   3,440,580     3,440,580  
                     Less: prior accumulated amortization   (430,072 )   (430,072 )
    11,084,082     10,805,210  
             
  $  15,462,626   $  15,320,018  

Amortization expense was charged to plant operations for the following periods:

    September 30,  
    2014     2013  
             
Three months ended $  45,421   $  62,361  
Nine months ended   136,264     187,043  

-20-


Estimated aggregate amortization expense for the next five years is as follows:

    Projected  
    Amounts  
Years ending December 31,      
                       2014 $  34,066  
                       2015   181,685  
                       2016   181,685  
                       2017   181,685  
                       2018   181,685  
       
  $  760,806  

NOTE 7 – PROVISION FOR INCOME TAXES

Income taxes are recorded based upon the liability method. Under this approach, deferred income taxes are recorded to reflect the tax consequences in future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at each year-end. A valuation allowance is recorded against deferred tax assets if management does not believe the Company has met the “more likely than not” standard imposed by accounting standards to allow recognition of such an asset.

At September 30, 2014, the Company had net deferred tax assets calculated at an expected rate, noted in the table below, of approximately $12,102,000 (December 31, 2013 - $10,435,000). As management of the Company cannot determine that it is more likely than not that the Company will realize the benefit of the net deferred tax asset, a valuation allowance equal to the net deferred tax asset was recorded at September 30, 2014 and December 31, 2013. For the current periods ended September 30, 2014 and 2013, the Company has recognized the net deferred income tax asset to the extent of the impact created from current book earnings. During the year ended December 31, 2013, the Company engaged a tax matters consultant to evaluate the value and timing of adjusting the deferred tax valuation allowance. The Company anticipates that any tax obligations will be fully offset by the utilization of prior reserved deferred tax benefits for the year ended December 31, 2014.

The significant components of the net deferred tax asset calculated with the estimated effective income tax rate at September 30, 2014 and December 31, 2013 were as follows:

    September 30,     December 31,  
    2014     2013  
Deferred tax assets*:            
       Net operating loss carry forward $  31,658,000   $  28,478,000  
       Stock based compensation   1,291,000     1,117,000  
             
Deferred tax liabilities*:            
         Depreciation and amortization   (20,847,000 )   (19,160,000 )
Net deferred income tax asset   12,102,000     10,435,000  
Estimated deferred tax asset recognized and utilized in current period   (739,000 )   (1,578,000 )
Deferred tax asset valuation allowance   (11,363,000 )   (8,857,000 )
             
Net deferred tax asset $  -   $  -  

* - significant components of deferred assets and liabilities are considered to be long-term.

-21-


The Company’s estimated effective income tax rate is as follows:

    For the Years Ended December 31,  
    2014     2013  
             
U.S. Federal statutory rate   34.0%     34.0%  
Average State and foreign income tax, net of federal tax effect   4.2     4.2  
Production tax credits   -     -  
         Net effective tax rate   38.2%     38.2%  

At September 30, 2014, the Company had net income tax operating loss carry forwards of approximately $82,875,000 ($74,550,000 in December 31, 2013), which expire in the years 2023 through 2034. The change in the allowance account from December 31, 2013 to September 30, 2014 was an increase of $640,000 for the anticipated deferred tax allocations based on 2014 income.

The net change in the deferred tax asset valuation allowance account is detailed as follows:

    For the Nine        
    Months Ended     For the Year  
    September 30,     Ended December  
    2014     31, 2013  
             
Change in net operating loss $  3,180,000   $  16,258,000  
Change in estimated effective tax rate   -     614,000  
Net change in difference between book and tax stock compensation costs   174,000     251,000  
Change in estimated deferred tax asset recognized and utilized in current period   839,000     (1,578,000 )
 Change in period book to income tax depreciation   (1,687,000 )   (17,518,000 )
             
         Net change in deferred tax valuation allowance $  2,506,000   $  (1,973,000 )

At December 31, 2013, Raft River Energy I LLC has a book-to-tax difference of $35.7 million due to the acceleration of intangible drilling costs and depreciation. By contract, 99% percent of this book-to-tax difference has been allocated to the non-controlling interest and would not be available to the consolidated group to offset future tax liabilities. At December 31, 2013, USG Oregon LLC has a book-to-tax difference of $38.1 million due to the acceleration of depreciation.

On April 22, 2014, the Company purchased a group of companies (see note 16 for details). Federal and applicable state NOLs that totaled approximately $30 million were included in the acquisition. These NOLs are scheduled to expire in the years ending 2028 through 2033. The use of these NOLs is restricted by the Company’s basis and the “applicable federal rate” as defined by federal tax law. The estimated reduced value of approximately $4.8 million is included in the Company’s calculated NOLs.

Although Management believes that its estimates are reasonable, no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our tax provisions. Ultimately, the actual tax benefits to be realized will be based upon future taxable earnings levels, which are very difficult to predict.

Accounting for Income Tax Uncertainties and Related Matters

The Company may be assessed penalties and interest related to the underpayment of income taxes. Such assessments would be treated as a provision of income tax expense on the financial statements. For the year ended December 31, 2013, nine months ended December 31, 2012 and the fiscal year ended March 31, 2012, no income tax expense has been realized as a result of operations and no income tax penalties and interest have been accrued related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and in the States of Idaho, California and Oregon. These filings are subject to a three year statute of limitations. The Company’s evaluation of income tax positions included the year ended December 31, 2013, the nine months ended December 31, 2012 and the fiscal year ended March 31, 2012 could be subject to agency examinations as of December 31, 2013. No filings are currently under examination. No adjustments have been made to reduce the estimated income tax benefit at fiscal year end. Any valuations relating to these income tax provisions will comply with U.S. Generally Accepted Accounting Principles.

-22-


NOTE 8 - CAPITAL LEASE OBLIGATIONS

Effective May 10, 2012, the Company entered into two capital lease obligations for the purchase of a boom lift and a telehandler from Caterpillar Financial Services Corporation. The boom lift contract is payable in 36 monthly payments of $1,094 that began on June 11, 2012 and has an effective annual interest rate of 5.985%. The telehandler contract is payable in 36 monthly payments of $3,155 that began on June 11, 2012 and has an effective annual interest rate of 6.14%. Both contracts with Caterpillar Financial Services Corporation have bargain purchase options at the end of the contracts scheduled for May 2015. At September 30, 2014, all of the lease obligations were considered to be current.

The scheduled future lease payments for the two contracts are presented as follows:

      Capital Lease  
Years ending December 31,     Amounts  
2014   $  12,749  
2015     21,249  
Total future payments     33,998  
         
Less: imputed interest portion     (771 )
    $  33,227  

At September 30, 2014, the net book value of the equipment under capital lease amounted to $46,391 ($155,000, less $108,609 accumulated amortization).

NOTE 9 – NOTES PAYABLE

U.S. Department of Energy
On August 31, 2011, USG Oregon LLC (“USG Oregon”), a subsidiary of the Company, completed the first funding drawdown associated with the U.S. Department of Energy (“DOE”) $96.8 million loan guarantee (“Loan Guarantee”) to construct its power plant at Neal Hot Springs in Eastern Oregon (the “Project”). The U.S. Treasury’s Federal Financing Bank, as lender for the Project, issues payments direct to vendors. All loan advances covered by the Loan Guarantee have been made under the Future Advance Promissory Note (the “Note”) dated February 23, 2011. Upon the occurrence and continuation of an event of default under the transaction documents, all amounts payable under the Note may be accelerated. In connection with the Loan Guarantee, the DOE has been granted a security interest in all of the equity interests of USG Oregon, as well as in the assets of USG Oregon, including a mortgage on real property interests relating to the Project site. The loan advances began August 31, 2011 and the last advance was taken on July 31, 2013. No additional advances are allowed under the terms of the loan. A total of 13 draws were taken and each individual draw or tranche is considered to be a separate loan. On August 12, 2013, proceeds of the ITC cash grant were distributed in accordance with the loan agreement, with $11,870,137 of the proceeds being used to prepay the Project loan, $11,167,473 of proceeds being used to fund a series of Project reserves, and balance of $9,711,930 being distributed as equity to the project owners. After the loan prepayment, the remaining final loan balance was $70,386,576. The loan principal is scheduled to be paid over 21.5 years with semi-annual installments including interest is calculated at an aggregate fixed interest rate of 2.598%. The principal payment amounts are calculated on a straight-line basis according to the life of the loans and the original loan principal amounts. The principal portion of the aggregate loan payment is adjusted as individual tranches are extinguished. The principal payments are scheduled to start at $1,709,963 and are expected to be reduced to $1,626,251 on February 10, 2017. The loan balance at September 30, 2014 totaled $66,974,610 (estimated current portion $3,419,927).

-23-


Loan advances/tranches and effective annual interest rates are details as follows:

              Annual Interest  
Description    
Amount
      Rate %  
Advances by date:                
     August 31, 2011*   $  2,328,422       2.997  
     September 28, 2011     10,043,467       2.755  
     October 27, 2011     3,600,026       2.918  
     December 2, 2011     4,377,079       2.795  
     December 21, 2011     2,313,322       2.608  
     January 25, 2012     8,968,019       2.772  
     April 26, 2012     13,029,325       2.695  
     May 30, 2012     19,497,204       2.408  
     August 27, 2012     7,709,454       2.360  
     December 28, 2012     2,567,121       2.396  
     June 10, 2013     2,355,316       2.830  
     July 3, 2013*     2,242,628       3.073  
     July 31, 2013*     4,026,582       3.214  
      83,057,965          
Principal paid through September 30, 2014     (16,083,355 )        
                 
Loan balance at September 30, 2014   $  66,974,610          

* - Individual tranches have been fully extinguished.

SAIC Constructors LLC
Effective August 27, 2010, the Company’s wholly owned subsidiary (USG Nevada LLC) signed a construction loan agreement with SAIC Constructors LLC (“SAIC”). The new 9.0 net megawatt power plant was considered complete and operational for financial reporting purposes on September 1, 2012. On February 15, 2013, USG Nevada LLC signed a settlement agreement with SAIC that defined the terms of three separate debt components to settle the obligations incurred under the construction loan agreement. As of December 31, 2013, two components of the settlement agreement were paid in full. On April 30, 2013, SAIC signed a loan agreement with Nevada USG Holdings LLC (parent company of USG Nevada LLC and wholly owned subsidiary of the Company), that further defined the terms of the remaining debt component of $2 million. This remaining obligation will be repaid in quarterly installments of $119,382, including interest at 7.0% per annum that began on July 31, 2013. The loan balance at September 30, 2014 totaled $1,580,007 (estimated current portion $383,196).

Prudential Capital Group
On September 26, 2013, the Company’s wholly owned subsidiary (USG Nevada LLC) entered into a note purchase agreement with the Prudential Capital Group’s related entities (“Prudential”) to finance the Phase I San Emidio geothermal project located in northwest Nevada. The term of the note is approximately 24 years, and bears interest at fixed rate of 6.75% per annum. Interest payments are due quarterly. Principal payments are due quarterly based upon minimum debt service coverage ratios established according to operating results and available cash balances. All amounts owing under the notes and the note purchase agreement or any related financing document are secured by USG Nevada LLC’s right, title and interest in and to its real and personal property, including the San Emidio project and the equity interests in USG Nevada LLC. At September 30, 2014, the balance of the loan was $30,417,843 (estimated current portion $471,091).

-24-


Auto Loans
On August 21, 2014, the Company’s wholly owned subsidiaries (U.S. Geothermal Services, LLC, USG Nevada LLC and Raft River Energy I, Inc.) purchased three trucks with down payments that totaled $47,000 and three separate loan agreements with Chrysler Capital. The loans require total monthly payments of $1,257, including interest at an average rate of 7.9% per annum until September 2020. The notes are secured by the vehicles. At September 30, 2014, the loan balances totaled $71,245 (estimated current portion $9,361)

Based upon the terms of the notes payable and expected conditions that may impact some of those terms, the estimated annual principal payments were calculated as follows:

For the Fiscal Year Ended     Principal  
September 30,     Payments  
2015   $  4,283,575  
2016     4,385,203  
2017     4,342,385  
2018     4,141,392  
2019     3,998,006  
Thereafter     77,893,144  
         
    $  99,043,705  

NOTE 10 - CAPITAL STOCK

The Company is authorized to issue 250,000,000 shares of common stock. All shares have equal voting rights, are non-assessable and have one vote per share. Voting rights are not cumulative and, therefore, the holders of more than 50% of the common stock could, if they choose to do so, elect all of the directors of the Company.

On September 3, 2014, the Company issued 2,459,460 shares of common stock to an investor exercising stock purchase warrants at a price of $0.50 per share.

On April 2, 2014, the Company issued 559,122 shares of common stock (restricted shares) at a price of $0.74 per share to employees.

During the quarter ended June 30, 2014, the Company issued 352,500 shares of common stock as a result of employees and former employees exercising stock options priced at $0.31 per share.

During the quarter ended March 31, 2014, the Company issued 724,500 shares of common stock as a result of employees and former employees exercising stock options priced between $0.31 and $0.46 per share.

On March 14, 2014, the Company issued 135,136 shares of common stock to an investor exercising stock purchase warrants at a price of $0.50 per share.

-25-


During the year ended December 31, 2013, the Company issued 577,778 shares of common stock (300,000 restricted shares) to an employee of the Company at prices between $0.35 and $0.36 per share under the terms of an employment agreement.

NOTE 11 - STOCK BASED COMPENSATION

The Company has a stock incentive plan (the “Stock Incentive Plan”) for the purpose of attracting and motivating directors, officers, employees and consultants of the Company and advancing the interests of the Company. The Stock Incentive Plan is a 15% rolling plan approved by shareholders in December 2009 and September 2013, whereby the Company can grant options to the extent of 15% of the current outstanding common shares. Under the plan, all forfeited and exercised options can be replaced with new offerings. As of September 30, 2014, the Company can issue stock option grants totaling up to 15,945,789 shares. Options are typically granted for a term of up to five years from the date of grant. Stock options granted generally vest over a period of eighteen months, with 25% vesting on the date of grant and 25% vesting every six months thereafter. The Company recognizes compensation expense using the straight-line method of amortization. Historically, the Company has issued new shares to satisfy exercises of stock options and the Company expects to issue new shares to satisfy any future exercises of stock options. At September 30, 2014, the Company had 11,848,500 options granted and outstanding.

On September 23, 2014, 68,000 stock options exercisable at a price of $1.58 expired without exercise.

During the quarter ended September 30, 2014, 50,000 stock options exercisable at the price of $0.83 issued to a contractor were forfeited due to the termination of their contract.

On April 2, 2014, the Company awarded 2,883,500 stock options at an exercise price of $0.74 expiring on April 2, 2019 to its employees and directors.

During the quarter ended June 30, 2014, 352,500 stock options exercisable at the price of $0.31 were exercised by employees and former employees.

On May 26, 2014, 1,698,250 stock options exercisable at a price of $0.92 expired without exercise.

During the quarter ended March 31, 2014, 724,500 stock options exercisable at prices between $0.31 and $0.46 were exercised by employees and former employees.

On February 22, 2014, 30,000 stock options exercisable at a price of $0.46 issued to employees were forfeited due to the termination of employment.

On September 25, 2013, 95,000 stock options exercisable at a price of $1.78 expired without exercise.

On September 1, 2013, the Company granted 15,000 stock options to an employee exercisable at a price of $0.41 until September 1, 2018.

On July 22, 2013, the Company granted 1,950,000 stock options to employees exercisable at a price of $0.46 until July 22, 2018.

On May 26, 2013, 6,375 stock options exercisable at a price of $0.92 were forfeited due to employee termination.

On May 19, 2013, 1,465,000 stock options exercisable at a price of $2.22 expired without exercise.

-26-


On April 19, 2013, the Company granted 1,250,000 stock options to employees exercisable at a price of $0.35 until April 19, 2023.

The following table reflects the summary of stock options outstanding at December 31, 2012 and changes for the year ended December 31, 2013 and nine months ended September 30, 2014:

          Weighted              
          Average     Weighted        
    Number of     Exercise     Average     Aggregate  
    shares under     Price Per     Fair     Intrinsic  
    options     Share     Value     Value  
                         
Balance outstanding, December 31, 2012   10,239,625   $  0.91   $  0.55   $  5,606,309  
                         
     Forfeited/Expired   (1,566,375 )   2.18     1.20     (1,872,094 )
     Exercised   -     -     -     -  
     Granted   3,215,000     0.42     0.25     808,500  
Balance outstanding, December 31, 2013   11,888,250     0.61     0.38     4,542,715  
                         
     Forfeited/Expired   (1,846,250 )   0.53     0.26     (1,251,738 )
     Exercised   (1,077,000 )   0.32     0.16     (171,134 )
     Granted   2,883,500     0.74     0.40     1,153,400  
Balance outstanding, September 30, 2014   11,848,500   $  0.62   $  0.36   $  4,273,243  

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model using the assumptions noted in the following table. Expected volatilities are based on historical volatility of the Company’s stock. The Company uses historical data to estimate option volatility within the Black-Scholes model. The expected term of options granted represents the period of time that options granted are expected to be outstanding, based upon past experience and future estimates and includes data from the Plan. The risk-free rate for periods within the expected term of the option is based upon the U.S. Treasury yield curve in effect at the time of grant. The Company currently does not foresee the payment of dividends in the near term.

The fair value of the stock options granted was estimated using the Black-Scholes option-pricing model and is amortized over the vesting period of the underlying options. The assumptions used to calculate the fair value are as follows:

    For the Nine  
    Months Ended For the Year
    September 30, Ended December
    2014 31, 2013
  Dividend yield 0 0
  Expected volatility 81-100% 71-81%
  Risk free interest rate 0.69-0.82% 0.27-0.82%
  Expected life (years) 3.19 4.63

Changes in the subjective input assumptions can materially affect the fair value estimate and, therefore, the existing models do not necessarily provide a reliable measure of the fair value of the Company’s stock options.

-27-


The following table summarizes information about the stock options outstanding at September 30, 2014:

  OPTIONS OUTSTANDING              
              REMAINING     NUMBER OF        
  EXERCISE     NUMBER OF     CONTRACTUAL     OPTIONS        
  PRICE     OPTIONS     LIFE (YEARS)     EXERCISABLE     INTRINSIC VALUE  
                             
$  0.86     1,300,000     0.95     1,300,000   $  752,207  
  0.83     2,540,000     1.68     2,540,000     1,244,600  
  0.60     100,000     1.95     100,000     36,072  
  0.31     1,865,000     2.90     1,865,000     290,128  
  0.46     1,895,000     3.81     1,421,250     345,222  
  0.41     15,000     3.92     11,250     2,259  
  0.35     1,250,000     8.55     937,500     253,500  
  0.74     2,883,500     4.50     720,875     287,232  
$  0.62     11,848,500     3.77     8,895,875   $  3,211,220  

The following table summarizes information about the stock options outstanding at December 31, 2013:

  OPTIONS OUTSTANDING              
              REMAINING     NUMBER OF        
  EXERCISE     NUMBER OF     CONTRACTUAL     OPTIONS        
  PRICE     OPTIONS     LIFE (YEARS)     EXERCISABLE     INTRINSIC VALUE  
                             
$  0.92     1,698,250     0.40     1,698,250   $  1,200,208  
  1.58     68,000     0.73     68,000     26,435  
  0.86     1,300,000     1.70     1,300,000     752,207  
  0.83     2,590,000     2.43     2,590,000     1,269,100  
  0.60     100,000     2.70     100,000     36,072  
  0.31     2,917,000     3.65     2,187,750     340,332  
  0.46     1,950,000     4.56     487,500     118,414  
  0.41     15,000     4.67     3,750     753  
  0.35     1,250,000     9.30     625,000     169,000  
$  0.61     11,888,250     3.43     9,060,250   $  3,912,521  

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A summary of the status of the Company’s nonvested stock options outstanding at December 31, 2012 and changes during the year ended December 31, 2013 and nine months ended September 30, 2014 are presented as follows:

          Weighted     Weighted  
          Average Grant     Average  
    Number of     Date Fair Value     Grant Date  
    Options     Per Share     Fair Value  
                   
Nonvested, December 31, 2012   2,212,750   $  0.31   $  0.16  
     Granted   3,215,000     0.42     0.25  
     Vested   (2,599,750 )   0.35     0.23  
     Forfeited/Expired   -     -     -  
Nonvested, December 31, 2013   2,828,000     0.39     0.23  
     Granted   2,162,625     0.74     0.40  
     Vested   (2,038,000 )   0.38     0.19  
     Forfeited/Expired   -     0.46     0.24  
Nonvested, September 30, 2014   2,952,625   $  0.65   $  0.36  

As of September 30, 2014, there was $924,876 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.5 years. The total fair value of options vested at September 30, 2014 and December 31, 2013 was $911,009 and $683,143, respectively.

Stock Compensation Plan (Restricted Shares)

On April 19, 2013, the Company granted an officer and director 300,000 common shares valued at $0.35 per share, which were distributed at the end of a one-year vesting period subsequent to period end. The recipient meets the vesting requirements by maintaining employment and good standing with the Company through the vesting period. After vesting, there are no restrictions on the shares. These shares were issued in July 2013 to the recipient and held by the Company until vested. The total fair value of options at the grant date was $105,000 and the recognized cost through September 30, 2014 was $31,208.

On April 2, 2014, the Company issued 559,122 shares of Company stock at a price of $0.74 that fully vest on April 2, 2015 to its employees and directors. The total fair value at the grant date was $413,750 and the recognized cost through September 30, 2014 was $156,554.

Stock Purchase Warrants

At September 30, 2014, the outstanding broker warrants and share purchase warrants consisted of the following:

          Broker              
          Warrant     Share     Warrant  
    Broker     Exercise     Purchase     Exercise  
Expiration Date   Warrants     Price     Warrants     Price  
September 16, 2015   246,285   $  1.25     4,104,757   $  1.25  
May 23, 2017   255,721     0.44     -     -  
December 21, 2017   -     -     3,310,812     0.50  

On September 3, 2014, 2,459,460 share purchase warrants were exercised by an investor at the warrant exercise price of $0.50.

-29-


On March 14, 2014, 135,136 share purchase warrants were exercised by an investor at the warrant exercise price of $0.50.

On February 2013, 500,000 stock purchase warrants at an exercise price of $5.00 expired without exercise.

NOTE 12 – FAIR VALUE MEASUREMENT

Current U.S. generally accepted accounting principles establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to the Company’s needs.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on its Consolidated Balance Sheet as of September 30, 2014 at fair value on a recurring basis:

    Total     Level 1     Level 2     Level 3  
Assets:                        
Money market accounts * $  27,448,313   $  27,448,313   $  -   $  -  

* - Money market accounts include both restricted and unrestricted funds.

As allowed by current financial reporting standards, the Company has elected not to implement fair value recognition and reporting for all non-financial assets and non-financial liabilities, except for those that are recognized or disclosed at fair value in the financial statements on a recurring basis, that is, at least annually.

-30-


NOTE 13 - RELATED PARTY TRANSACTIONS

At September 30, 2014 and December 31, 2013 the amounts of $11,473 and $3,089; respectively, were payable to the officers of the Company for routine expense reimbursement. These amounts are unsecured and due on demand.

The Company paid directors’ fees for the nine months ended September 30, 2014 and 2013 totalled $87,900 and $76,500; respectively.

NOTE 14 - COMMITMENTS AND CONTINGENCIES

Operating Lease Agreements
The Company has entered into several lease agreements with terms expiring up to December 1, 2034 for geothermal properties in Washoe County Nevada; Republic of Guatemala; Neal Hot Springs, Oregon and adjoining the Raft River properties in Raft River, Idaho. The Company incurred total lease expenses for the nine months ended September 30, 2014 and 2013, of $419,868 and $286,923; respectively.

BLM Lease Agreements
The Company believes that it is in compliance with all of the following lease terms.

Idaho
On August 1, 2007, the Company signed a geothermal resources lease agreement with the United States Department of the Interior Bureau of Land Management (“BLM”). The contract requires an annual payment of $3,502 including processing fees. The primary term of the agreement is 10 years. After the primary term, the Company has the right to extend the contract. BLM has the right to terminate the contract upon written notice if the Company does not comply with the terms of the agreement.

San Emidio
The lease contracts are for approximately 21,905 acres of land and geothermal rights located in the San Emidio Desert, Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases require the lessee to conduct operations in a manner that minimizes adverse impacts to the environment.

Gerlach
The Gerlach Geothermal LLC assets are comprised of two BLM geothermal leases and one private lease totaling 3,615 acres. Both BLM leases have a royalty rate which is based upon 10% of the value of the resource at the wellhead. The amounts are calculated according to a formula established by Minerals Management Service (“MMS”). One of the two BLM leases has a second royalty commitment to a third party of 4% of gross revenue for power generation and 5% for direct use based on BTUs consumed at a set comparable price of $7.00 per million BTU of natural gas. The private lease has a 10 year primary term and would receive a royalty of 3% gross revenue for the first 10 years and 4% thereafter.

Granite Creek
The Company has three geothermal lease contracts with the BLM for the Granite Creek properties. The lease contracts are for approximately 2,443.7 acres of land and geothermal water rights located in North Western Nevada. The lease contracts have primary terms of 10 years. Per federal regulations applicable for the contracts, the lessee has the option to extend the primary lease term another 40 years if the BLM does not need the land for any other purpose and the lessee is maintaining production at commercial quantities. The leases state annual lease payments of $2,444, not including processing fees, and expire October 2017.

-31-


Raft River Energy I LLC
The Company has entered into several lease contracts for approximately 1,298 acres of land and geothermal water rights located in the Raft River area located in Southern Idaho. The contracts expire from March 2013 to December 2033. The contracted lease payments are scheduled for $31,287 for the year ended December 31, 2014.

The Geysers, California
On April 22, 2014, the Company acquired companies that held five significant lease contracts for approximately 3,809 acres (6.0 square miles) of land and geothermal water rights in The Geysers area located in Northern California. The contracts have stated expiration dates, expiring from February 2017 to October 2019. The remaining contracts renew indefinitely with payments made within contracted terms (held by payment). The contracted lease payments are scheduled for $274,000 for the year ended December 31, 2014.

Office Lease

Park Center Boulevard
On August 12, 2013, the Company signed a 5 year lease agreement for office space and janitorial services. The lease payments are due in monthly installments starting February 1, 2014. The monthly payments that began February 1, 2014 have two components which include a base rate of $3,234 that is not subject to increase and a rate beginning at $6,418 that is adjusted annually according to the cost of living index. The contract includes a 5 year extension option. For the nine months ended September 30, 2014, the office lease costs totaled $86,873.

Tyrell Lane
Under the contract, the lease payments were due in monthly installments of $6,535. The contract ended January 31, 2014. The total office lease costs incurred under the contract and the prior contract for year ended December 31, 2013 totaled $78,423 ($58,817 for the nine months ended September 30, 2013).

Contracted Lease Obligation Schedule

The following is the total contracted lease operating obligations (operating leases, BLM lease agreements and office leases) for the next five years:

Year Ending        
December 31,     Amount  
2014   $  188,891  
2015     824,869  
2016     856,156  
2017     851,094  
2018     807,751  
Thereafter     14,197,270  

Power Purchase Agreements

Raft River Energy I LLC
The Company signed a power purchase agreement with Idaho Power Company for the sale of power generated from its joint venture Raft River Energy I LLC. The Company also signed a transmission agreement with Bonneville Power Administration for transmission of electricity from this plant to Idaho Power. These agreements will govern the operational revenues for the initial phases of the Company’s operating activities.

-32-


USG Nevada LLC
As a part of the purchase of the assets from Empire Geothermal Power, LLC and Michael B. Stewart acquisition (“Empire Acquisition”), a power purchase agreement with Sierra Pacific Power Company was assigned to the Company. The contract had a stated expected output of 3,250 kilowatts maximum per hour and extended through 2017. During the year ended March 31, 2012, the power purchase agreement was replaced by a new amended and restated 25 year contract signed in December of 2011 that sets the new rate at $89.75 per megawatt hour with a 1% annual escalation rate. The new contract currently allows for a maximum of 73,444 megawatt hours annually that will be paid for at the full contract price. Upon declaration of commercial operation under the PPA, an Operating Security Deposit is required to be maintained at NV Energy for the full term of the PPA. As of September 30, 2014, the Company has funded a security deposit of $1,468,898.

USG Oregon LLC
In December of 2009, the Company’s subsidiary (USG Oregon LLC), signed a power purchase agreement with Idaho Power Company for the sale of power generated by the Neal Hot Springs, Oregon project. The agreement has a term of 25 years and provides for the purchase of power up to 25 megawatts (22 megawatt planned annual average output level). Beginning 2012, the flat energy price is $96.00 per megawatt hour. The price escalates annually by 3.9% in the initial years and by 1.0% during the latter years of the agreement. The approximate 25-year levelized price is $117.65 per megawatt hour.

Asset Retirement Obligations (“AROs”)

The Geysers, California
On April 22, 2014, the Company completed the acquisition of a group of companies owned by Ram Power Corp.’s (“Ram”) Geysers Project located in Northern California. Two of the acquired companies (Western GeoPower, Inc. and Etoile Holdings, Inc.) contained asset retirement obligations that, primarily, originate with the environmental regulations defined by the laws of the State of California. The liabilities related to the removal and disposal of arsenic impacted soil and existing steam conveyance pipelines are estimated to total $800,000. Obligations related to decommissioning four existing wells were estimated to total $600,000. These obligations are based upon the expected future value of the remedy or settlement and the values have not been calculated at discounted rates. At September 30, 2014, the Company has not considered it necessary to specifically fund these obligations. Since management is still evaluating the development plan for this project that could eliminate or significantly reduce these obligations, no charges directly associated the asset retirement obligations have been charged to operations. All of the obligations are considered to be long-term at September 30, 2014.

Raft River Energy I LLC, USG Nevada LLC, and USG Oregon LLC
These Companies operate in Idaho, Nevada and Oregon and are subject to environmental laws and regulations of these states. The plants, wells, pipelines and transmission lines are expected to have long useful lives. Generally, these assets will require funds for retirement or reclamation. However, these estimated obligations are believed to be less than or not significantly more than the assets’ estimated salvage values. Therefore, as of September 30, 2014, no retirement obligations have been recognized.

401(k) Plan
The Company offers a defined contribution plan qualified under section 401(k) of the Internal Revenue Code to all its eligible employees. All employees are eligible at the beginning of the quarter after completing 3 months of service. Subsequent to June 30, 2013, the Company began matching 50% of the employee’s contribution up to 6%. Prior to June 30, 2013, the plan required the Company to match 25% of the employee’s contribution up to 6%. Employees may contribute up to the maximum allowed by the Internal Revenue Code. The Company made matching contributions to the plan that totaled $74,435 and $37,448 for the nine months ended September 30, 2014 and 2013, respectively.

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NOTE 15 – JOINT VENTURES/NON-CONTROLLING INTERESTS

Non-controlling interests included on the consolidated balance sheets of the Company are detailed as follows:

    September 30,     December 31,  
    2014     2013  
             
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC $  404,346   $  404,352  
Oregon USG Holdings LLC interest held by Enbridge Inc.   23,162,048     35,926,826  
Raft River Energy I LLC interest held by Raft River I Holdings, LLC   21,214,303     21,824,302  
  $  44,780,697   $  58,155,480  

Gerlach Geothermal LLC
On April 28, 2008, the Company formed Gerlach Geothermal, LLC (“Gerlach”) with our partner, Gerlach Green Energy, LLC (“GGE”). The purpose of the joint venture is the exploration of the Gerlach geothermal system, which is located in northwestern Nevada, near the town of Gerlach. Based upon the terms of the members’ agreement, the Company owns a 60% interest and GGE owns a 40% interest in Gerlach Geothermal, LLC. The agreement gives GGE an option to maintain its 40% ownership interest as additional capital contributions are required. If GGE dilutes to below a 10% interest, their ownership position in the joint venture would be converted to a 10% net profits interest. The Company has contributed $757,190 in cash and $300,000 for a geothermal lease and mineral rights; and the GGE has contributed $704,460 of geothermal lease, mineral rights and exploration data. During the nine months ended September 30, 2014, contributions were made to Gerlach by the Company and GGE that totaled $11,040 and $7,360; respectively.

The consolidated financial statements reflect 100% of the assets and liabilities of Gerlach, and report the current non-controlling interest of GGE. The full results of Gerlach’s operations are reflected in the statement of operations with the elimination of the non-controlling interest identified.

Oregon USG Holdings LLC
In September 2010, the Company’s subsidiary, Oregon USG Holdings LLC (“Oregon Holdings”), signed an Operating Agreement with Enbridge Inc. (“Enbridge”) for the right to participate in the Company’s project in the Neal Hot Springs project located in Malheur County, Oregon. On February 20, 2014, a new determination under the existing agreement was reached with Enbridge that established their ownership interest percentage at 40% and the Company’s at 60%, effective January 1, 2013. Oregon Holdings has a 100% ownership interest in USG Oregon LLC. Enbridge has contributed a total of $32,801,000, including the debt conversion, to Oregon Holdings in exchange for a direct ownership interest. During the nine months ended September 30, 2014, distributions were made to the Company and Enbridge that totaled $12,388,606 and $15,024,334; respectively.

The consolidated financial statements reflect 100% of the assets and liabilities of Oregon Holdings and USG Oregon LLC, and report the current non-controlling interest of Enbridge. The full results of Oregon Holdings and USG Oregon LLC’s operations are reflected in the statement of operations with the elimination of the non-controlling interest identified.

Raft River Energy I LLC (“RREI”)
Raft River Energy I is a joint venture between the Company and Raft River I Holdings, LLC a subsidiary of the Goldman Sachs Group, Inc. An Operating Agreement governs the rights and responsibilities of both parties. At fiscal year end, the Company had contributed approximately $17.9 million in cash and property, and RREI has contributed approximately $34.1 million in cash. Profits and losses are allocated to the members based upon contractual terms. For income tax purposes, Raft River I Holdings, LLC receives a greater proportion of the share of losses and other income tax benefits. This includes the allocation of production tax credits, which will be distributed 99% to Raft River I Holdings, LLC and 1% to the Company during the first 10 years of production. During the initial years of operations, Raft River I Holdings, LLC will receive a larger allocation of cash distributions.

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The consolidated financial statements reflect 100% of the assets and liabilities of RREI, and report the current non-controlling interest of Raft River I Holdings LLC. The full results of Raft River Energy I LLC’s operations are reflected in the statement of operations with the elimination of the non-controlling interest identified.

Effective May 17, 2011, a repair services agreement (“RSA”) was executed between RREI and U.S. Geothermal Services, LLC for the purpose of funding repairs of two underperforming wells. The agreement defined terms of the RSA repair costs and RSA repair management fees that would be funded by the loan. The outstanding loan balance will accrue interest at 12.0% per annum. The RSA payments will be made preferentially from project cash flow at a rate of 90% of increased cash created by the repairs and cash availability on a quarterly basis. The repairs were completed in January 2012. Based upon the financial conditions applicable to the loan, RREI did not make any payments during the year ended December 31, 2012. As of December 31, 2012, the loan balance amounted to $2,136,150. During the nine months ended September 30, 2014 and the year ended December 31, 2013, RREI made principal payments on the loan of $662,556 and $755,288; respectively. The balance of the loan at September 30, 2014 and December 31, 2013 was $718,306 and $1,380,862; respectively. The loan balance and related interest effects are fully eliminated during the consolidation process.

NOTE 16 – ACQUISITION OF RAM POWER’S GEYSERS PROJECT

On April 22, 2014, the Company acquired all of the ownership shares of a group of companies owned by Ram Power Corp.’s (“Ram”) that hold all interests in the Geysers Project located in Northern California for a total of $6.78 million ($6.4 million purchase price, plus $0.38 million in other acquisition costs). The acquisition included Ram’s subsidiaries: Western GeoPower, Inc., Skyline Geothermal Holdings, Inc., and Etoile Holdings, Inc. which includes all membership interests in Mayacamas Energy LLC and Skyline Geothermal LLC. The assets acquired included 4 production/injection wells, restricted cash, land and geothermal water rights. The Company assumed the on-going liabilities of the companies which included an asset retirement obligations with estimated value of $1.4 million. The Company will evaluate whether to construct a power plant or sell the steam to one of the existing power companies in the area. The total acquisition cost was allocated as follows:

    Acquisition Costs  
Assets:      
     Restricted cash, short term well bond $  100,000  
     Land   1,603,516  
     Geothermal water rights   278,872  
     Construction in progress:      
             Wells   6,139,420  
             Plant and facilities   60,637  
    8,182,445  
Liabilities:      
     Asset retirement obligations   (1,400,000 )
Net acquisition cost $  6,782,445  

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NOTE 17 - SUBSEQUENT EVENTS

The Company has evaluated events and transactions that have occurred after the balance sheet date through November 13, 2014, which is considered to be the issuance date. The following event was identified for disclosure:

Earth Power Resources (“EPR”) Merger Agreement
On October 16, 2014, the Company announced the signing of an Agreement and Plan of Merger with EPR. Under the terms of the Agreement, the EPR shareholders will receive a total of 692,700 shares of U.S. Geothermal Inc. stock in exchange for all outstanding shares of EPR stock. The transaction is expected to be completed by the end of November 2014 following EPR shareholder approval. Acquired assets include geothermal leases covering 26,017 acres in the State of Nevada representing three projects.

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Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

INFORMATION REGARDING FORWARD LOOKING STATEMENTS

This document contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements involve a number of risks and uncertainties. We caution readers that any forward-looking statement is not a guarantee of future performance and that actual results could differ materially from those contained in the forward-looking statement. These statements are based on current expectations of future events. You can find many of these statements by looking for words like “believes,” “expects,” “anticipates,” “intend,” “estimates,” “may,” “should,” “will,” “could,” “plan,” “predict,” “potential,” or similar expressions in this document or in documents incorporated by reference in this document. Examples of these forward-looking statements include, but are not limited to:

  • our business and growth strategies;

  • our future results of operations;

  • anticipated trends in our business;

  • the capacity and utilization of our geothermal resources;

  • our ability to successfully and economically explore for and develop geothermal resources;

  • our exploration and development prospects, projects and programs, including timing and cost of construction of new projects and expansion of existing projects;

  • availability and costs of drilling rigs and field services;

  • our liquidity and ability to finance our exploration and development activities;

  • our working capital requirements and availability;

  • our illustrative plant economics;

  • market conditions in the geothermal energy industry; and

  • the impact of environmental and other governmental regulation.

These forward-looking statements are based on the current beliefs and expectations of our management and are subject to significant risks and uncertainties. If underlying assumptions prove inaccurate or unknown risks or uncertainties materialize, actual results may differ materially from current expectations and projections. The following factors, among others, could cause actual results to differ from those set forth in the forward-looking statements:

  • the failure to obtain sufficient capital resources to fund our operations;

  • unsuccessful construction and expansion activities, including delays or cancellations;

  • incorrect estimates of required capital expenditures;

  • increases in the cost of drilling and completion, or other costs of production and operations;

  • the enforceability of the power purchase agreements for our projects;

  • impact of environmental and other governmental regulation, including delays in obtaining permits or ongoing impacts of the sequester;

  • hazardous and risky operations relating to the development of geothermal energy;

  • our ability to successfully identify and integrate acquisitions;

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  • the failure of the geothermal resource to support the anticipated power capacity;

  • our dependence on key personnel;

  • the potential for claims arising from geothermal plant operations;

  • general competitive conditions within the geothermal energy industry; and

  • financial market conditions.

All subsequent written or oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. We do not undertake any obligation to release publicly any revisions to these forward-looking statements to reflect events or circumstances after the date of this document or to reflect the occurrence of unanticipated events, except as may be required under applicable U.S. securities law. If we do update one or more forward-looking statements, no inference should be drawn that we will make additional updates with respect to those or other forward-looking statements.

The U.S. dollar is the Company’s functional currency. All references to “dollars” or “$” are to United States dollars.

General Background and Discussion

The following discussion should be read in conjunction with our unaudited consolidated financial statements for the quarter ended September 30, 2014 and notes thereto included in this report.

U.S. Geothermal Inc. (“the Company”) is a Delaware corporation. The Company’s common stock trades on the NYSE MKT LLC under the trade symbol “HTM” and on the Toronto Stock Exchange under the symbol “GTH”.

For the quarter ended September 30, 2014, the Company was focused on:

  1)

Operating and optimizing the Neal Hot Springs, San Emidio and Raft River power plants;

  2)

Leasing additional lands, and constructing a new drill pad at El Ceibillo;

  3)

Drilling two new wells and constructing a tie in pipeline at San Emidio for Phase II;

  4)

Finalizing merger agreement for Earth Power Resources;

  5)

Pursuing PPA and steam sale opportunities at the WGP Geysers project; and

  6)

Evaluating potential new geothermal projects and acquisition opportunities.

Project Overview

The following is a list of projects that are in operation, under development or under exploration. Projects in operation have producing geothermal power plants. Projects under development have a geothermal resource discovery or may have wells in place, but require the drilling of new or additional production and injection wells in order to supply enough geothermal fluid sufficient to operate a commercial power plant. Projects under exploration do not have a geothermal resource discovery occurrence yet, but have significant thermal and other physical evidence that warrants the expenditure of capital in search of the discovery of a geothermal resource. Due to inflation and marketplace increases in the costs of labor and construction materials, previous estimates of property development costs may be low.

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  Projects in Operation  
            Generating       Contract
Project   Location   Ownership   Capacity (megawatts)   Power Purchaser   Expiration
Raft River (Unit I)   Idaho   JV(2)   13.0(1)   Idaho Power   2032
San Emidio (Unit I)   Nevada   100%   9.0   Sierra Pacific   2038
Neal Hot Springs   Oregon   JV(3)   22.0   Idaho Power   2036

(1)

Based on the designed annual average net output. The actual output of the Raft River Unit I plant currently is approximately 10.0 megawatts annual average.

(2)

As part of the financing package for Unit I of the Raft River project, we have contributed $16.5 million in cash and approximately $1.4 million in property to Raft River Energy I LLC, the Unit I project joint venture company. Raft River I Holdings, LLC, a subsidiary of The Goldman Sachs Group, contributed $34 million to finance the construction of the project.

(3)

In September 2010, the Company’s wholly owned subsidiary (Oregon USG Holdings LLC) entered into agreements that formulated a strategic partnership with Enbridge (U.S.) Inc. (“Enbridge”). Enbridge contributed approximately $32.8 million to the Neal Hot Springs geothermal project. Enbridge’s equity interest in the project is 40%.


Projects Under Development  
                    Estimated    
            Target   Projected   Capital    
            Development   Commercial   Required    
Project   Location   Ownership   (Megawatts)   Operation Date   ($million)   Power Purchaser
El Ceibillo Phase I   Guatemala   100%   25   3rd Quarter 2017   $135   MOU
San Emidio Phase II   Nevada   100%   11   4th Quarter 2016   $66   TBD
WGP Geysers   California   100%   26   TBD   TBD   TBD

 Additional Properties 
Project   Location   Ownership   Target Development (Megawatts)
Gerlach   Nevada   60%   TBD
Granite Creek   Nevada   100%   TBD
El Ceibillo Phase II   Guatemala   100%   25
San Emidio Phase III   Nevada   100%   17.2
Neal Hot Springs II   Oregon   100%   28
Raft River Unit II   Idaho   100%   26
Raft River Unit III   Idaho   100%   32
Vale Butte   Oregon   100%   TBD

Resource Details
    Property Size            
Property   (square miles)   Temperature (ºF)   Depth (Ft)   Technology
Raft River   10.8   275-302   4,500-6,000   Binary
WGP Geysers     6.0   500   6,000-10,000   Steam
San Emidio   35.8   289-316   1,500-3,000   Binary
Neal Hot Springs     9.6   285-300   2,500-3,000   Binary
Gerlach     5.6   338-352   2,000-3,000   Binary
Granite Creek     3.8   TBD   TBD   Binary
El Ceibillo   38.6   410-526   1,800-TBD   Steam
Vale Butte     0.6   290-300   TBD   Binary

Neal Hot Springs, Oregon
Neal Hot Springs is located in Eastern Oregon near the town of Vale, the county seat of Malheur County. The Neal Hot Springs facility is a 22 megawatt net annual average power plant, consisting of three separate, 7.33 net megawatt annual average modules. The facility achieved commercial operation under the terms of the power purchase agreement on November 16, 2012. Generation from the facility during the third quarter of 2014 totaled 32,264 megawatt-hours with an average of 14.74 net megawatts per hour of operation. Plant availability was 99.1% during the quarter.

The PPA for the project was signed on December 11, 2009 with the Idaho Power Company. The PPA has a 25 year term with a starting annual average price of $96.00 per megawatt-hour beginning in 2012 and escalates at a variable percentage annually. On May 20, 2010, the Idaho Public Utilities Commission approved the PPA with no changes to the terms and conditions. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.3% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $102.78 per megawatt-hour.

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San Emidio, Nevada
The Phase I power plant at San Emidio is located approximately 100 miles north-east of Reno, Nevada near the town of Gerlach, and achieved commercial operation on May 25, 2012. Generation from the facility during the third quarter 2014 totaled 18,240 megawatt-hours, with an average of 8.6 net megawatts per hour of operation. Plant availability was 96.1% during the quarter.

On June 1, 2011, an amended and restated PPA was signed with Sierra Pacific Power Company d/b/a NV Energy for the sale of up to 19.9 megawatts of electricity on an annual average basis. The PPA was approved by the Public Utility Commission of Nevada on December 27, 2011. The PPA has a 25 year term with a base price of $89.75 per megawatt-hour, and a 1% annual escalation rate. The average price paid under the PPA for 2014 has increased to $91.17 per megawatt-hour.

As a result of the delays experienced in permitting additional wells on BLM administered leases, it has been determined that it is not possible to complete the development of the Phase II project within the development time frame required in the existing 19.9 megawatt NV Energy PPA. The Phase II expansion is dependent on successful development of additional production and injection well capacity. The cost of development for Phase II is estimated at approximately $66 million. We expect that approximately 75% of the Phase II development may be funded by project loans, with the remainder funded through equity financing. We anticipate the project qualifying for the federal investment tax credit.

A Small Generator Interconnection Agreement for 16 megawatts of transmission capacity was executed with Sierra Pacific Power Company on December 28, 2010. An application to increase the interconnection agreement to the full 19.9 megawatts allowed under the PPA was submitted to NV Energy on January 9, 2014. A System Impact Study agreement, which is the next step in the interconnection process mandated by the Federal Energy Regulatory Commission, was signed on August 28.

On October 30, 2009, the Company was awarded $3.77 million in Recovery Act funding for the exploration and development of its San Emidio geothermal power project using advanced geophysical exploration techniques. This award was categorized under the “Innovative Exploration and Drilling Projects” section of the American Recovery and Reinvestment Act. The first stage of the DOE project applied innovative, seismic and satellite imagery techniques along with state-of-the-art structural modeling, to locate large aperture fractures that represent high-productivity geothermal drilling targets and was completed in 2011. Two zones along the 4.5 mile long San Emidio fault structure were identified as high quality targets for drilling during the first phase of the DOE program, a South Zone and a North Zone.

The second stage of the DOE program is a 50-50 cost shared drilling plan that is intended to follow up on targets identified in the first stage. Drilling started in the South Zone, and two wells were completed by the Company. After approval of the drilling program by the DOE in November 2011, one of the first two wells was deepened and three additional wells were completed in the South Zone with the costs being shared on a 50-50 basis.

Permitting was initiated with the Bureau of Land Management (“BLM”) for four new observation wells to be drilled in the South Zone to follow up on the high temperatures found in wells 61-21 (302°F) and 45-21 (316°F). As part of the permitting process, cultural and biological surveys were performed, and the well design and drilling program were submitted during the quarter. Permits for three wells were issued by the BLM on April 29th and a drill rig was mobilized to the site on June 26th. Two additional wells were completed on the BLM administered land during the third quarter. Well OW-14 was drilled to a depth of 3,501 feet and had a bottomhole temperature of 265°F. Well OW-15 was drilled to a depth of 3,716 feet and had a maximum downhole temperature of 300°F. While the wells extended the high temperature outline of the South Zone, neither well encountered the commercial permeability seen in well 61-21 (OW-10). Geologic, geochemical and temperature data generated by the drilling program is being evaluated to determine the next phase of drilling.

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Well 61-21 (formerly OW-10) in the South Zone, was reworked beginning on October 25, 2013 and was completed on November 2, 2013. Flow testing of 61-21 was completed during the second quarter of 2014. To allow for early, long term testing of the South Zone resource area, a cross tie pipeline was constructed between the Phase I and Phase II project areas and a production pump was installed in well 61-21 during the third quarter. Well 61-21 is currently producing 630 gallons per minute of 298°F fluid to the San Emidio Phase I power plant.

A Request for Proposal (“RFP”) from NV Energy for 100 megawatts of renewable energy was issued on October 1, 2014. We are evaluating the RFP requirements and anticipate submitting a bid for the Phase II project if it qualifies. In parallel, we are investigating pursuing a power purchase agreement with California power off-takers, where power prices are typically higher.

Raft River, Idaho
The Raft River project is located in Southern Idaho, near the town of Malta, and achieved commercial operation in January 2008. Generation from the facility during the third quarter 2014 totaled 18,500 megawatt-hours, with an average of 8.41 net megawatts per hour of operation. Plant availability was 99.7% during the quarter.

The PPA for the project was signed on September 24, 2007 with the Idaho Power Company. The PPA has a 25 year term with a starting average price for the year 2007 of $52.50 that escalates at 2.1% per year. The Idaho Power PPA has a seasonal pricing structure that pays 120% of the average price for four months (July, August, November, December), 100% of the average price for five months (January, February, June, September, October) and 73.5% of the average price for three months (March, April, May). The average price paid under the PPA for 2014 has increased to $60.72 per megawatt-hour. In addition to the price paid for energy by Idaho Power, Raft River currently receives $4.75 per megawatt-hour under a separate contract for the sale of Renewable Energy Credits to Holy Cross Energy, a Colorado electric cooperative.

The project was awarded an $11.4 million cost-shared, thermal fracturing program grant from the Department of Energy, with the goal of creating an Enhanced Geothermal System (EGS) by creating fractures and developing a corresponding increased permeability in low permeability rock. Well RRG-9 was made available, and after installing four, 300 foot deep seismic monitoring wells and seismic geophones, to allow for seismic monitoring, the first stage of injection into the well began in June 2013, with the well capable of receiving only 20 gallons per minute (gpm) of water due to the low permeability of the rock. Injection continued through the quarter from power plant injectate, with flow into the well seeing a moderate increase to now over 380 gpm, indicating that additional permeability is developing. The EGS stimulation is expected to continue through 2015.

If the fracturing program is successful, and permeability is improved to a commercial level, well RRG-9 may be utilized as a production or injection well for the existing Raft River power plant. The Company’s contributions for the thermal fracturing program are made in-kind by the use of the RRG-9 well, well field data, and monitoring support.

Republic of Guatemala
A geothermal energy rights concession located 14 kilometers southwest of Guatemala City was awarded to U.S. Geothermal Guatemala S.A., a wholly owned subsidiary of the Company in April 2010. The concession has a 5 year term for the development and construction of a power plant. There are 24,710 acres (100 square kilometers) in the concession which is at the center of the Aqua and Pacaya twin volcano complex.

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An office and staff are located in Guatemala City, and 17 acres of surface has been under lease. Recent temperature gradient drilling has identified the primary area of interest to be larger than earlier anticipated, so an additional surface lease of 80 acres was signed on October 15, 2014, bringing the total surface leasehold interest to 97 acres. Construction of a drill pad, pond and cellar on this new lease for proposed well EC-2, has been completed. Drilling of EC-2 is expected to begin as soon as the approval to extend the development schedule contained in the concession agreement has been obtained from the Guatemalan Ministry of Energy and Mines. We are optimistic that we will receive approval of our application shortly.

The El Ceibillo project, is located near the town of Amatitlan, in a developed industrial zone immediately adjacent to the highway that connects Guatemala City to the Port of San Jose on the Pacific coast. An initial development of a 25 megawatt (Phase I) power plant is planned in the El Ceibillo area of the concession, but the final size of the facility will be determined after drilling and resource delineation has advanced. Initial transmission studies have been completed, and have identified the grid interconnection point approximately 1.2 miles (2 kilometers) from the site.

A temperature gradient (“TG”) drilling program was initiated during the first quarter of 2014 with a series of 656 foot (200 meter) deep wells planned. Nine TG wells have been completed with depths ranging from 656 to 1,312 feet (200 to 400 meters). Bottom-hole temperatures found in this shallow drilling program range from 176 to 413°F (80 to 211°C) with two of the wells encountering permeability and flowing brine. The data from these wells provided a more accurate temperature gradient map of the underlying geothermal resource which has assisted in identifying future drilling targets.

A first phase of drilling took place during the third quarter of 2013 when well EC-1 was drilled to a depth of 4,829 feet (1,472 meters) and encountered a bottom hole temperature of 491°F (255°C), with the temperature gradient at the bottom of the hole rising at a rate of 7.1°F/100 Feet (129.1°C/km). High temperatures in excess of 392°F (>200°C) were encountered in the well beginning at a depth of 2,625 feet (800 meters), which represents a potential high temperature reservoir interval in excess of 2,204 feet (672 meters) thick. Due to the high temperature gradient found in the lower section of the well, the decision was made to deepen the well. The final depth of the well is 5,650 feet (1,722 meters) with a measured bottom-hole temperature of 526°F (274°C). Clean out and short term flow tests were conducted along with temperature surveys and have been incorporated in the geologic model of the reservoir. Well EC-1 did not encounter commercial permeability.

In early September 2013, the Guatemalan Ministry of the Environment and Natural Resources (“MARN”) issued the Environmental License for the construction and operation of the planned, first phase, 25 megawatt power plant at the El Ceibillo site. The license is based on the Environmental Impact Assessment Study that was submitted in December 2012, describing the initial design of the 25 megawatt facility, and requires the submittal of final design specifications for review by MARN prior to starting physical construction of the plant. Additionally, the license requires compliance with all legal and regulatory requirements under Guatemalan law, submittal of an air quality monitoring plan, and that final design comply with the strict guidelines for noise, dust and hydrogen sulfide emissions. Prior to issuance of the license, an environmental bond was posted with the Ministry of Environment and Natural Resources.

A binding Memorandum of Understanding (“MOU”) was signed on October 18, 2012 with one of the largest power brokers in Central America. The MOU establishes the framework for a PPA that includes a 15-year term for an initially estimated 25 megawatts of power generation up to a maximum of 50 megawatts of power generation. The MOU includes a project power price that the Company believes is competitive with the prevailing energy prices in the region. Several conditions precedent must be met before the PPA is negotiated and becomes effective, including confirming the geothermal reservoir by an independent reservoir engineer, obtaining all required permits and authorizations, and securing a project finance commitment.

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The MOU may be terminated (i) as a result of the bankruptcy of any of the parties, (ii) on January 1, 2015, unless such date is extended by mutual agreement, because the construction of the project has not been initiated and/or the commercial operation date has been moved beyond the date set out in the PPA framework, or (iii) if the geothermal resource found lacks the conditions to sustain a long-term commercial production that allows electric power to be produced under the necessary conditions of profitability.

The El Ceibillo geothermal project area had nine previous wells drilled into the geothermal concession during the 1990s which have depths ranging from 560 to 2,000 feet (170 to 610 meters). A few of those wells had adequate flow and temperature to support a direct use application. Six of the wells had measured reservoir temperatures in the range of 365°F to 400°F and had high conductive gradients that indicated rapidly increasing temperature with depth. Fluid samples and mineralization from the wells indicated the existence of a high permeability reservoir below or near the existing well field.

WGP Geysers
The WGP Geysers project is located in the broader Geysers geothermal field located approximately 75 miles north of San Francisco, California. The broader Geysers geothermal field is the largest producing geothermal field in the world generating more than 850 megawatts of power for more than 30 years. Acquisition of the WGP Geysers Project from Ram Power was completed on April 22, 2014 for $6.4 million.

WGP Geysers is an advanced stage project that encompasses the former Pacific Gas and Electric Unit 15, which once had a 62 megawatt (gross) capacity geothermal power plant that was shut down in l989. The project includes 3,809 acres of geothermal leases and property, development design plans, and permits for a proposed 26 (net) megawatt power plant. There are four existing wells drilled in 2008-2009 which are immediately available for production or injection, with a fifth, historic well that has temporary plugs installed but can be reworked. The four new wells have been tested with an initial steam flow totaling 462,000 pounds per hour. A report prepared in 2012 by a third party reservoir engineering firm, states that the total initial power capacity from these wells is estimated at about 30 megawatts (gross). The report further estimated that the sustainable long-term production from the resource is conservatively estimated at 26 megawatts (net) assuming 25% of the geothermal fluid that is withdrawn is injected back into the reservoir.

A 12 month extension for the Sonoma County Conditional Use Permit to construct the 26 megawatt power plant was applied for and was approved on June 12, 2014. Additionally, an application was made to the Sonoma County Air Quality Board for a permit to conduct flow tests on the four production wells drilled in 2009. The Air Quality permit was approved on June 19, 2014.

We continue to evaluate the detailed design and project costs for two development scenarios: 1) build a new power plant and sell electricity, or 2) build pipelines and sell steam. Discussions are underway with counterparties for both scenarios, and we are reviewing several California based renewable energy contract solicitations for which the project may qualify. Designs for each scenario are being optimized, and we are refining our detailed cost estimates and associated economic models.

Gerlach Joint Venture
The Gerlach Joint Venture, located adjacent to the town of Gerlach in Washoe County, Nevada is made up of both private and BLM geothermal leases. The Peregrine well, a historic exploration slim hole that encountered a lost circulation zone at a depth of 975 feet, was redrilled and the hole was opened from a 6.5 inch diameter well to a 12.5 inch diameter well. Lost circulation was confirmed with three zones through the 900 to 1,024 foot interval. The well was stopped at 1,070 feet total depth. Temperature surveys and a short clean out flow test were conducted on the well. The well flowed at an estimated 300-400 gallons per minute with a flowing temperature of 208°F. Geochemistry calculated from brine samples indicates an average potential source temperature of 374°F for the Gerlach site.

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To continue evaluation of the Gerlach resource, deepening of well 18-10A commenced on October 29, 2014. The 18-10A well, which is a twin to a previously drilled well, was drilled to a depth of 1,900 feet in 2012, but was not completed at the time. The original 18-10 well was drilled to a total depth of 2,868 feet in 1994 but was plugged and abandoned in 2006, before we acquired the property. The original well encountered a very promising, total lost circulation zone at a depth of 2,788 feet, but the well was not flow tested and the resource temperature is undetermined. The current drilling plan has a permitted depth of up to 3,000 feet. The U.S. Geological Survey considered the Gerlach resource to be the 3rd largest geothermal resource in the state of Nevada in their Assessment of Geothermal Resources of the United States published in l975.

Operating Results

For the nine months ended September 30, 2014, the Company reported net income attributable to the Company of $268,388 ($0.00 income per share) which represented a $284,361 increase from the net loss of $15,973 reported in the same period in 2013 ($0.00 loss per share). For the three months ended September 30, 2014, the Company reported net income attributable to the Company of $81,780 ($0.00 income per share) which represented an increase of $109,917 from the net loss of $28,137 reported in the same period in 2013 ($0.00 loss per share). Generally, favorable variances were reported related to the operations of the Company’s three power plants. Notable favorable variances were reported in professional and management fees, salaries and wages, and exploration costs. A notable unfavorable variance was reported in stock based compensation.

Plant Operations
During the nine months ended September 30, 2014, the Company’s energy production revenues and related operating costs originated from its three fully operational power plants. The San Emidio plant (USG Nevada LLC) is located in the San Emidio Desert in the northwestern part of the State of Nevada. The original San Emidio plant and related water rights were purchased in 2008. The old plant ceased operations in December 2011 and was replaced with a new plant that began commercial operations in May 2012. The Raft River plant (Raft River Energy I LLC) is located in South Eastern Idaho. The Raft River plant began operations in January of 2008. The new plant at Neal Hot Springs, Oregon (USG Oregon LLC) is located by Vale, Oregon and began commercial operations on November 16, 2012.

A summary of energy sales by plant location for the two reporting periods are as follows:

    For the Nine Months Ended September 30,  
    2014     2013  
    $     %     $     %  
Energy sales by plant:                        
       Neal Hot Springs, Oregon   12,381,761     59.5     9,508,241     54.2  
       San Emidio, Nevada   5,048,736     24.3     4,886,568     27.9  
       Raft River, Idaho   3,379,757     16.2     3,147,758     17.9  
    20,810,254     100.0     17,542,567     100.0  

% - represents the percentage of total Company energy sales.

-44-



    For the Three Months Ended September 30,  
    2014     2013  
    $     %     $     %  
Energy sales by plant:                        
       Neal Hot Springs, Oregon   3,712,988     55.9     2,875,686     50.8  
       San Emidio, Nevada   1,663,119     25.0     1,531,260     27.0  
       Raft River, Idaho   1,273,013     19.1     1,260,124     22.2  
    6,649,120     100.0     5,667,070     100.0  

% - represents the percentage of total Company energy sales.

A quarterly summary of megawatt hours generated by plant are as follows:

  For the Quarter Ended,
  September December 31, March 31, June 30, September
  30, 2013 2013 2014 2014 30, 2014
Neal Hot Spring, Oregon 25,832 53,445 56,047 40,629 32,246
San Emidio, Nevada 18,317 21,112 21,223 15,686 18,240
Raft River, Idaho 18,687 21,951 21,614 18,069 18,501
  62,836 96,508 98,884 74,384 68,987

Neal Hot Springs, Oregon (USG Oregon LLC) Plant Operations
The Neal Hot Springs plant was considered to be commercially operational on November 16, 2012. The quarter ended March 31, 2013, was the plant’s first full quarter of operations. For the nine months ended September 30, 2014, net income was $5,678,878 which was an increase of $1,906,097 (50.5% increase) from net income from the same period ended 2013. For the three months ended September 30, 2014, net income was $1,412,124 which was an increase of $583,290 (70.4% increase) from net income from the same period ended 2013.

For the nine months ended September 30, 2014, plant energy revenues increased 30.2% (29.1% for the three months ended September 30, 2014) from the same period ended 2013. The increase in energy sales for the current periods compared to 2013 was primarily due to less down time at the plant. For the third quarter of 2013, the plant’s three units experienced a total of 928 hours of lost production which was significantly less than the 59 hours of lost production in the third quarter of 2014. The largest loss in third quarter of 2013 was due to the failure of the refrigerant pump at unit one (618 hours). In April 2014, the plant lost a total of 400.5 hours due to the scheduled maintenance shutdown. In 2013, the plant did not have a scheduled maintenance shutdown since it was still undergoing commissioning and was experiencing notable outages from February through June (1,417 total hours).

Plant operating costs increased $915,260 ($113,075 for the three months ended September 30, 2014), which was a 21.0% increase (6.9% increase for the three months ended September 30, 2014) for the nine months ended September 30, 2014 from the same period ended 2013. The largest variances were noted in administrative support, insurance, and plant and well field maintenance costs. For the nine months ended September 30, 2014 administrative and corporate support costs increased $219,789 ($65,559 for the three months ended September 30, 2014), which was a 62.4% increase (56.2% increase for the three months ended September 30, 2014) from the same period in 2013. Effective 2014, a contracted monthly corporate support fee of $13,750 was established. Additional consulting fees related to the general plant maintenance that amounted to over $40,600 were incurred for the nine months ended September 30, 2014.

For the nine months ended September 30, 2014, the plant’s insurance costs totaled $303,847 ($94,347 for the three months ended September 30, 2014), which was an increase of $183,199 ($10,461 for the three months ended September 30, 2014) from the same period in 2013. In July 2013, the plant’s insurance coverage transferred from a builders’ risk policy to a full property coverage policy which resulted in a significant increase in cost. In May of 2014, an insurance rate adjustment was made that reduced premiums by approximately 20%.

-45-


Plant and field maintenance costs increased $316,220 ($52,342 for the three months ended September 30, 2014), which was a 102.5% increase (28.3 % for the three months ended September 30, 2014) for the nine months ended September 30, 2014 from the same period ended 2013. In May 2014, a turbine seal was replaced at a cost of 62,298. In the current quarter, costs that exceeded $169,000 were incurred to repair a feed pump and an expansion joint for Unit 1, repair piping modules for all three units, and rebuild a seal for Unit 2. In July 2013, the plant’s Engineering, Procurement and Construction Company turned over plant maintenance responsibilities to the Company; therefore, most of the repair costs incurred after June 30, 2013, were not covered under warranty.

Summarized statements of operations for the Neal Hot Springs, Oregon plant are as follows:

    Nine Months Ended September 30,  
    2014     2013     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   12,381,761     100.0     9,508,241     100.0     2,873,520     30.2  
                                     
Plant expenses:                                    
       General operations   2,838,259     22.9     1,962,217     20.6     (876,042 )   (44.6 )
       Depreciation and amortization   2,443,525     19.8     2,404,307     25.3     (39,218 )   (1.6 )
    5,281,784     42.7     4,366,524     45.9     (915,260 )   (21.0 )
                                     
                   Operating income   7,099,977     57.3     5,141,717     54.1     1,958,260     38.1  
                                     
Other income (expense):                                    
       Interest expense   (1,436,902 )   (11.6 )   (1,395,112 )   (14.7 )   (41,790 )   (3.0 )
       Other and interest income   15,803     0.1     26,176     0.3     (10,373 )   (39.6 )
    (1,421,099 )   (11.5 )   (1,368,936 )   (14.4 )   (52,163 )   (3.8 )
                                     
                   Net income   5,678,878     45.8     3,772,781     39.7     1,906,097     50.5  

  % -

represents the percentage of total plant operating revenues.

  %* -

represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

The intercompany elimination adjustments for interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary’s operations.

-46-



    Three Months Ended September 30,  
    2014     2013     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   3,712,988     100.0     2,875,686     100.0     837,302     29.1  
                                     
Plant expenses:                                    
       General operations   953,313     25.7     835,161     29.0     (118,152 )   (14.1 )
       Depreciation and amortization   805,497     21.7     810,574     28.2     5,077     0.6  
    1,758,810     47.4     1,645,735     57.2     (113,075 )   (6.9 )
                                     
                   Operating income   1,954,178     52.6     1,229,951     42.8     724,227     58.9  
                                     
Other income (expense):                                    
       Interest expense   (546,676 )   (14.7 )   (412,899 )   (14.4 )   (133,777 )   (32.4 )
       Other and interest income   4,622     0.1     11,782     0.4     (7,160 )   (60.8 )
    (542,054 )   (14.6 )   (401,117 )   (13.9 )   (140,937 )   (35.1 )
                                     
                   Net income   1,412,124     38.0     828,834     28.9     583,290     70.4  

  % -

represents the percentage of total plant operating revenues.

  %* -

represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

The intercompany elimination adjustments for interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary’s operations.

Key quarterly production data for the Neal Hot Springs, Oregon plant is summarized as follows:

     Mega-       Ave. Rate       Depreciation
    watt   Energy   per       &
     Hours   Sales   Megawatt   Net Income*   Amortization
Quarter Ended:   Produced   ($)   Hour ($)   ($)   ($)
December 31, 2012    23,256   2,329,030   88.7   1,451,523   256,670
March 31, 2013    46,137   4,197,252   90.6   2,424,648   779,299
June 30, 2013    30,016   2,435,304   80.2   518,754   814,434
September 30, 2013    25,832   2,875,686   110.9   829,374   810,573
December 31, 2013    53,445   6,058,169   113.3   3,644,359   812,766
March 31, 2014    56,047   5,266,455   93.8   3,070,349   817,503
June 30, 2014    40,629   3,402,318   83.7   1,196,404   820,526
September 30, 2014    32,246   3,712,988   115.0   1,412,124   805,497

 

*-

The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary’s net income.

San Emidio, Nevada Plant Energy Sales and Plant Operating Expenses (USG Nevada LLC)
For the nine months ended September 30, 2014, the San Emidio plant reported net income of $329,441 which was a decrease of $648,260 (66.3% decrease) from the $977,701 in net income reported in the same period in 2013. For the three months ended September 30, 2014, the San Emidio plant reported net income of $109,515 which was a decrease of $245,983 (69.2% decrease) from the net income of $355,498 reported in the same quarter in 2013. During the current quarter, the plant produced 18,240 megawatt hours, which was consistent with the same quarter in 2013. The 8.6% increase in energy sales for the quarter was primarily due to the annual contracted rate increase.

-47-


For the nine months ended September 30, 2014, operating expenses, excluding depreciation, increased $590,825 (36.1% increase) from the same period ended 2013. For the three months ended September 30, 2014, operating expenses, excluding depreciation, increased $425,428 (143.3% increase) from the same period ended 2013. The primary factors for the increases incurred in regulatory testing and property taxes costs. In the second and third quarters of 2014, the plant incurred costs that exceeded $106,000 on regulatory testing of injection well casing. In the second quarter of 2013, the plant collected a property tax refund that totaled $226,860, which offset 2013 property tax costs. In the quarter ended September 30, 2013, the Company collected a PEC revenue shortfall charge refund of $283,000 that was originally paid and expensed in the second quarter of 2013. This cost and subsequent refund did not impact total expense for the nine months ended September 30, 2013.

For the nine months ended September 30, 2014, the plant’s interest expense increased $352,413 (29.5% increase) from the same period ended 2013. During the quarter ended March 31, 2013, the plant loan had not been finalized and most of the interest incurred under the contractor’s obligations was capitalized. In the three months ended March 31, 2013, the plant incurred interest costs that totaled $621,712.

Summarized statements of operations for the San Emidio, Nevada plant are as follows:

    Nine Months Ended September 30,  
    2014     2013     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   5,048,736     100.0     4,886,568     100.0     162,168     3.3  
                                     
Plant expenses:                                    
       Operations   2,226,674     44.1     1,635,849     33.5     (590,825 )   (36.1 )
       Depreciation and amortization   945,828     18.7     1,080,228     22.1     134,400     12.4  
    3,172,502     62.8     2,716,077     55.6     (456,425 )   (16.8 )
                                     
                   Operating income   1,876,234     37.2     2,170,491     44.4     (294,257 )   (13.6 )
                                     
Other income (expense):                                    
       Interest expense   (1,546,958 )   (30.6 )   (1,194,545 )   (24.4 )   (352,413 )   (29.5 )
       Other income   165     0.0     1,755     0.0     (1,590 )   (90.6 )
    (1,546,793 )   (30.6 )   (1,192,790 )   (24.4 )   (354,003 )   (29.7 )
                                     
                   Net income   329,441     6.6     977,701     20.0     (648,260 )   (66.3 )

  % -

represents the percentage of total plant operating revenues.

  %* -

represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary’s net operating income/loss.

-48-



    Three Months Ended September 30,  
    2014     2013     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   1,663,119     100.0     1,531,260     100.0     131,859     8.6  
                                     
Plant expenses:                                    
       Operations   722,361     43.5     296,933     19.4     (425,428 )   (143.3 )
       Depreciation and amortization   316,638     19.0     307,854     20.1     (8,784 )   (2.9 )
    1,038,999     62.5     604,787     39.5     (434,212 )   (71.8 )
                                     
                   Operating income   624,120     37.5     926,473     60.5     (302,353 )   (32.6 )
                                     
Other income (expense):                                    
       Interest expense   (514,693 )   (30.9 )   (572,710 )   (37.4 )   58,017     10.1  
       Other income   88     0.0     1,735     0.1     (1,647 )   (94.9 )
    (514,605 )   (30.9 )   (570,975 )   (37.3 )   56,370     9.9  
                                     
                   Net income   109,515     6.6     355,498     23.2     (245,983 )   (69.2 )

  % -

represents the percentage of total plant operating revenues.

  %* -

represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary’s net operating income/loss.

Key quarterly production data for the San Emidio, Nevada plant is summarized as follows:

     Mega-       Ave. Rate       Depreciation
    watt   Energy   per   Net Income   &
     Hours   Sales   Megawatt      (Loss)*   Amortization
Quarter Ended:   Produced   ($)   Hour ($)   ($)   ($)
December 31, 2012   16,231   1,459,078   90.0   (223,412)   416,091
March 31, 2013   19,228   1,726,927   90.3   834,266   407,060
June 30, 2013   18,039   1,628,382   90.3   (212,058)   365,314
September 30, 2013   18,317   1,531,260   83.6   355,498   307,854
December 31, 2013   21,112   1,905,813   90.3   180,931   312,273
March 31, 2014   21,223   1,935,091   91.2   423,350   312,908
June 30, 2014   15,686   1,450,526   92.5   (203,424)   316,283
September 30, 2014   18,240   1,663,119   90.1   109,515   316,638

  *-

The intercompany elimination adjustments for management fees are not incorporated into the presentation of the subsidiary’s net income/loss.

Raft River, Idaho Unit I (Raft River Energy I LLC) Plant Operations
The net loss from Raft River Energy I LLC (“RREI”) operations of $400,539 for the nine months ended September 30, 2014, favorably decreased by $248,611 (38.3% decrease) from the net loss for the same period ended in 2013. The net income of $117,281 for the three months ended September 30, 2014, increased $118,447 from the net loss for the same quarter ended 2013. For the current quarter, both energy revenues ($1,273,013) and hours produced (18,501 hours) were consistent with the same quarter in ended 2013. For the nine months ended September 30, 2014, energy sales increased $231,999 (7.4% increase) from the same period ended 2013. The increase in energy sales for the nine months ended September 30, 2014 from the same period in 2013 was primarily due to increased production (14.9% increase) which was due to less downtime in the first and second quarters of 2014 (128 hours less) from the same quarters in 2013.

-49-


The summarized statements of operations for RREI are as follows:

    Nine Months Ended September 30,  
    2014     2013     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   3,379,757     92.5     3,147,758     91.9     231,999     7.4  
       Energy credit sales   274,590     7.5     277,992     8.1     (3,402 )   (1.2 )
    3,654,347     100.0     3,425,750     100.0     228,597     6.7  
                                     
Plant expenses:                                    
       General operations   2,691,094     73.6     2,539,931     74.1     (151,163 )   (6.0 )
       Depreciation and amortization   1,285,251     35.2     1,394,356     40.7     109,105     7.8  
    3,976,345     108.8     3,934,287     114.8     (42,058 )   (1.1 )
                                     
                   Operating loss   (321,998 )   (8.8 )   (508,537 )   (14.8 )   186,539     36.7  
                                     
Other income (expense):                                    
       Interest expense   (81,557 )   (2.2 )   (154,318 )   (4.5 )   72,761     47.2  
       Other and interest income   3,016     0.1     13,705     0.4     (10,689 )   (78.0 )
    (78,541 )   (2.1 )   (140,613 )   (4.1 )   62,072     44.1  
                                     
                     Net loss   (400,539 )   (10.9 )   (649,150 )   (18.9 )   248,611     38.3  

  % -

represents the percentage of total plant operating revenues.

  %* -

 represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

The intercompany elimination adjustments for interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary’s operations.

-50-



    Three Months Ended September 30,  
    2014     2013     Variance  
    $     %     $     %     $     %*  
Plant revenues:                                    
       Energy sales   1,273,013     93.5     1,260,124     93.1     12,889     1.0  
       Energy credit sales   87,885     6.5     93,425     6.9     (5,540 )   (5.9 )
    1,360,898     100.0     1,353,549     100.0     7,349     0.5  
                                     
Plant expenses:                                    
       General operations   795,172     58.5     856,455     63.2     61,283     7.2  
       Depreciation and amortization   429,164     31.5     450,222     33.3     21,058     4.7  
    1,224,336     90.0     1,306,677     96.5     82,341     6.3  
                                     
                   Operating income   136,562     10.0     46,872     3.5     89,690     191.4  
                                     
Other income (expense):                                    
       Interest expense   (21,830 )   (1.6 )   (48,122 )   (3.6 )   26,292     54.6  
       Other and interest income   2,549     0.2     84     0.0     2,465     #  
    (19,281 )   (1.4 )   (48,038 )   (3.6 )   28,757     59.9  
                                     
                   Net income (loss)   117,281     8.6     (1,166 )   (0.1 )   118,447     #  

  % -

represents the percentage of total plant operating revenues.

  %* -

represents the percentage of change from 2013 to 2014. Increases in revenues and decreases in expenses from the prior period to the current period are considered to be favorable and are presented as positive figures.

  #-

Variance percentage was extremely high or undefined.

The intercompany elimination adjustments for interest expense, management fees and lease costs are not incorporated into the presentation of the subsidiary’s operations.

Key quarterly production data for RREI is summarized as follows:

    Mega-       Ave. Rate       Depreciation
    watt   Energy   per   Net Income   &
    Hours   Sales   Megawatt   (Loss)*   Amortization
Quarter Ended:   Produced   ($)   Hour ($)   ($)   ($)
December 31, 2012    21,170   1,398,218   67.9   154,752   505,559
March 31, 2013    19,675   1,064,481   56.1   67,620   472,040
June 30, 2013    17,248   823,154   49.9   (715,605)   472,094
September 30, 2013    18,687   1,260,124   69.5   (1,166)   450,222
December 31, 2013    21,951   1,479,499   69.0   254,302   450,222
March 31, 2014    21,614   1,199,550   57.9   61,749   427,907
June 30, 2014    18,069   907,194   52.6   (579,569)   428,180
September 30, 2014    18,501   1,273,013   71.6   117,281   429,164

 

*-

Net income (loss) does not include intercompany elimination adjustments for interest expense, management fees and lease costs.

-51-


Professional and Management Fees
For the nine months ended September 30, 2014, the Company incurred professional and management fees of $754,796, which was a decrease of $225,415 (23.0% decrease) from the same period in 2013. For the three months ended September 30, 2014, the Company incurred professional and management fees of $186,849, which was a decrease of $62,012 (24.9% decrease) from the same period in 2013. In May 2013, the Company entered into a contract with the former CEO’s consulting firm. Consulting fees were paid to the former CEO that totaled $155,393 in the second quarter of 2013 ($182,284 for the nine months ended September 30, 2013). For the nine months ended September 30, 2014, fees were paid to the former CEO’s consulting firm totaled $57,161 ($3,000 for the three months ended September 30, 2014). The original contract ended April 2014, and was extended through December 2014 at a reduced rate of $1,000 per month. Consulting costs of $135,356 ($39,653 for the three months ended September 30, 2014) were paid to a geologist for the nine months ended September 30, 2014, which was an increase of $77,193 ($14,935 increase for the three months ended September 30, 2014). In the quarter ended March 31, 2013, the geologist was an employee and these costs were included in the Company salaries and wages. During the nine months ended September 30, 2014, the Company incurred audit/audit related, legal and SOX consulting costs that amounted to approximately $186,000, $171,000 and $91,000; respectively. During the nine months ended September 30, 2013, the Company incurred audit/audit related, legal and SOX consulting costs that amounted to approximately $244,000, $177,000 and $109,000; respectively. Audit fees were higher in the 2013 due the Company’s change in fiscal year end and two new audits of the Company’s subsidiaries.

Salaries and Wages
Salaries and wages include payroll and related costs incurred for exploration, design and development costs that cannot be capitalized, as well as general management and administration. Payroll and related costs for plant operations are expensed as plant production costs. For the nine months ended September 30, 2014, the Company reported $1,473,006 in salaries and related costs which was a decrease of $182,618 (11.0% decrease) from the same period in 2013. For the three months ended September 30, 2014, the Company reported $400,950 in salaries and related costs, which was a decrease of $136,532 (25.4% decrease) from the same period in 2013. Salaries and related costs for administration and development employees before allocations were $1,859,175 ($493,056 in the three months ended September 30, 2014), which was 19.1% (31.3% lower in the three months ended September 30, 2014) lower in the nine months ended September 30, 2014 than in the same period ended 2013. In the current nine months, fewer amounts of payroll costs ($311,977 less) were allocated to capital projects than in the same period in 2013. For the nine months ended September 30, 2013, the salary and related costs of approximately $372,000 ($46,000 for the three months ended September 30, 2013) were capitalized for design and other development activities for the Neal Hot Springs, Oregon project. In April 2014, the Company awarded raises to its employees that averaged 2.9%, and bonuses were awarded that totaled $376,750. In April 2013 and July 2013, employee bonuses were awarded that totaled $171,000 and $237,800; respectively.

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Management, administrative and development employee salaries and related costs are as follows:

    For the Nine Months Ended September 30,  
    2014     2013     Variance  
Financial Element   $     $     $     %  
                         
Total Company salary and related costs, excluding plant operations   1,859,175     2,297,858     (438,683 )   (19.1 )
                         
Salary allocations:                        
           Capital projects   (278,736 )   (590,713 )   311,977     52.8  
           Corporate management and support for plant operations   (107,432 )   (51,520 )   (55,912 )   (108.5 )
    1,473,007     1,655,625     (182,618 )   (11.0 )

% - represents the percentage of change from 2013 to 2014.
# - variance percentage that is extremely high or undefined.

    For the Three Months Ended September 30,  
    2014     2013     Variance  
Financial Element   $     $     $     %  
                         
Total Company salary and related costs, excluding plant operations   493,056     717,219     (224,163 )   (31.3 )
                         
Cost allocations:                        
           Capital projects   (66,552 )   (134,500 )   67,948     50.5  
           Corporate management and support for plant operations   (25,554 )   (45,237 )   19,683     (43.5 )
    400,950     537,482     (136,532 )   25.4  

% - represents the percentage of change from 2013 to 2014.

Stock Based Compensation
For the nine months ended September 30, 2014, the Company reported $1,098,771 in stock based compensation, which was an increase of $527,611 (92.4% increase) from the same period in 2013. For the three months ended September 30, 2014, the Company reported $321,306 in stock based compensation, which was an increase of $13,898 (4.5% increase) from the same period in 2013. Stock based compensation includes the calculated values for both Company stock and stock options granted to employees and board members. The Company uses the Black-Scholes option-pricing model to value the cost of the outstanding stock options. The higher value of the stock options for the current nine months ended September 30, 2014 was directly impacted by the number of outstanding options, the increase in the Company’s stock price and the related increase in the volatility of the Company’s stock price. On April 2, 2014, the Company awarded employees 2,883,500 stock options and 559,122 shares (restricted shares). In the prior year, the Company did not issue stock options to employees until July 22, 2013 (1,950,000 options, no restricted shares to employees). During the current nine months ended September 30, 2014, the Company’s common stock price reached a high of $0.95 and a low of $0.38 ($0.62 average daily closing price). During the nine months ended September 30, 2013, the Company’s common stock price reached a high of $0.59 and a low of $0.31 ($0.31 average daily closing price).

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The stock based compensation components are summarized as follows:

    For the Nine Months Ended              
    September 30,              
    2014     2013     Variances  
    $     $     $     %  
Total Stock Based Compensation:                        
       Stock option compensation   911,009     523,918     387,091     73.9  
       Stock compensation   187,762     47,242     140,520     297.5  
    1,098,771     571,160     527,611     92.4  

% - represents the percentage of change from 2013 to 2014.

    For the Three Months Ended              
    September 30,              
    2014     2013     Variances  
    $     $     $     %  
Total Stock Based Compensation:                        
       Stock option compensation   248,619     281,458     (32,839 )   (11.7 )
       Stock compensation   72,687     25,949     46,738     180.1  
    321,306     307,407     13,899     4.5  

% - represents the percentage of change from 2013 to 2014.

Exploration Costs
For the nine months ended September 30, 2014, the Company reported $70,709 in exploration costs (non-capitalized), which was a decrease of $438,465 (86.1% decrease) from the same quarter in 2013. For the three months ended September 30, 2014, the Company reported $27,221 in exploration costs (non-capitalized), which was an increase of $94,432 (95.3% increase) from the same quarter in 2013. During the nine months ended September 30, 2013, the Company incurred drilling costs that exceeded $473,000 ($472,000 for the three months ended September 30, 2013) on an exploration well for Phase II of the San Emidio, Nevada project. During the three months ended September 30, 2013, well drilling costs that exceeded $1,354,000 incurred at the project in Guatemala were capitalized. These costs were originally expensed in prior to the end of the third quarter 2013.

Net Income Attributable to the Non-Controlling Interests
The net income attributable to the non-controlling interest entities is the line item that removes the portion of the total consolidated operations that are owned by the Company’s subsidiaries. For the nine months ended September 30, 2014, the Company reported $1,666,191 in net income attributable to non-controlling interests, which was an increase of $1,195,567 from the $470,624 net income reported in the same period ended 2013. For the three months ended September 30, 2014, the Company reported $614,037 in net income attributable to non-controlling interests, which was an increase of $399,702 from the $214,335 net income reported in the same quarter ended 2013. The primary reason for the increase was due to the operations of the Neal Hot Springs plant which reported net income of $5,678,877, which was an increase of $1,906,097 for the nine months ended September 30, 2014 from the same period ended 2013. For the three months ended September 30, 2014, the USG Oregon LLC reported net income of $1,412,124, which was an increase of $583,290 for the same quarter ended 2013. The impact of the USG Oregon LLC’s operations on the Company’s reported income attributable to non-controlling entities was an increase of $762,439 ($233,316 increase for the three months) from the nine months ended September 30, 2013 as compared to the same period ended 2014.

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The net income or (loss) attributable to the non-controlling interest entities is detailed as follows:

    For the Nine Months Ended              
    September 30,              
Subsidiaries and Non-Controlling   2014     2013     Variance  
Interest Entities   $     $     $     %  
Oregon USG Holdings LLC interest held by Enbridge Inc.   2,259,557     1,312,348     947,209     72.2  
Raft River Energy I LLC interest held by Raft River I Holdings, LLC   (585,999 )   (834,472 )   248,473     29.8  
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC   (7,367 )   (7,252 )   (115 )   (1.6 )
    1,666,191     470,624     1,195,567     254.0  

% - represents the percentage of change from 2013 to 2014.

    For the Three Months Ended              
    September 30,              
Subsidiaries and Non-Controlling   2014     2013     Variance  
Interest Entities   $     $      $     %  
Oregon USG Holdings LLC interest held by Enbridge Inc.   564,850     285,167     279,683     98.1  
Raft River Energy I LLC interest held by Raft River I Holdings, LLC   55,467     (65,617 )   121,084     184.5  
Gerlach Geothermal LLC interest held by Gerlach Green Energy, LLC   (6,280 )   (5,215 )   (1,065 )   (20.4 )
    614,037     214,335     399,702     186.5  

% - represents the percentage of change from 2013 to 2014.

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The following is a summarized presentation of select financial line items from the statement of operations and the impact of the related non-controlling interests on each item presented:

    For the Three Months Ended     For the Nine Months Ended  
    September 30, 2014     September 30, 2014  
          Non-           Non-  
          Controlling           Controlling  
Statement of Operations   Consolidated     Interest     Consolidated     Interest  
Element   $     $     $     $  
Net income from plant operations   2,939,672     856,227     9,294,709     2,331,746  
Expenses (Income):                        
     Corporate administration, professional
       fees and promotion
  463,597     680     1,723,641     9,667  
     Salaries and wages   400,950     384     1,473,006     463  
     Stock based compensation   321,306     -     1,098,771     -  
     Exploration costs   27,221     5,217     70,709     6,218  
     Interest expense   1,089,686     240,282     3,079,415     658,519  
     Other (income) expenses   (58,905 )   (4,373 )   (85,412 )   (9,312 )
    2,243,855     242,190     7,360,130     665,555  
Net income before income taxes   695,817     614,037     1,934,579     1,666,191  

Off Balance Sheet Arrangements

As of September 30, 2014, the Company does not have any off balance sheet arrangements.

Liquidity and Capital Resources

We believe our cash and liquid investments at September 30, 2014 are adequate to fund our general operating activities through December 31, 2015. Other project development, such as Guatemala, Geysers and the San Emidio expansion, may require additional funding. In addition to government loans and grants discussed below, we anticipate that additional funding may be raised through financial and strategic partnerships, market loans, issuance of debt or equity, and/or through the sale of ownership interest in tax credits and benefits.

The recent financial credit crisis has not impacted the ability of our customers, Idaho Power Company and Sierra Pacific Power (NV Energy), to pay for their power. This power is sold under long-term contracts at fixed prices to large utilities. The status of the credit and equity markets could delay our project development activities while the Company seeks to obtain economic credit terms or a favorable equity market price to further the drilling and construction activities. The Company continues discussions with potential investors to evaluate alternatives for funding at the corporate and project levels.

On April 21, 2014, the Company completed the acquisition of Ram Power Corp.’s Geysers project for a total of $6.4 million in cash. The Ram subsidiaries included in the acquisition are Western GeoPower, Inc., Skyline Geothermal Holding, Inc., and Etoile Holdings Inc., which in turn includes all membership interests in Mayacamas Energy LLC and Skyline Geothermal LLC. The acquired Ram subsidiaries possess the full development interest in the project. These interests include all geothermal leases (covering 3809 acres), development design plans, and permits for a proposed 26 net megawatt power plant, and includes land and geothermal mineral rights ownership of the Mayacamas property purchased by Ram in 2010. This property contains 4 existing geothermal wells immediately available for production or injection and one historic well available for use after reworking. Finally, the acquisition includes a 50% undivided interest in the geothermal mineral rights relating to the property that contains the 5th existing well also purchased by Ram in 2010. The other 50% interest in this property is contained within an acquired leasehold interest.

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On November 29, 2013 the Company filed a replacement shelf registration statement on Form S-3 with the SEC. The replacement shelf registration statement was filed as routine course of business due to the impending expiration of the Company’s existing shelf registration statement that, under SEC rules, would have expired on December 1, 2013. Pursuant to SEC rules, the expiration date of the existing shelf registration statement has been extended until the earlier of the effective date of the replacement shelf registration statement or May 30, 2014. Upon effectiveness of the S-3 on February 4, 2014, the Company may use the replacement shelf registration statement to offer and sell from time to time for a period of three years in one or more public offerings up to $50 million of common stock, warrants, or units consisting of any combination thereof. The terms of any securities offered under the replacement shelf registration statement, and the intended use of the resulting net proceeds, will be established at the times of any future offerings and will be described in prospectus supplements filed at such times with the SEC. The Company has no immediate plans to sell any additional stock under the replacement shelf registration statement at this time, but wishes to preserve the option in support of its future growth and development of its projects as well as strategic M&A opportunities.

Following the receipt of the Section 1603 Federal Investment Tax Credit (ITC) cash grant payment, and the Oregon Business Energy Tax Credit funds, and after the receipt and disbursement of all remaining construction reserve funds, which was finalized on January 27, 2014, the final ownership interest in the Neal Hot Springs project was calculated in accordance with the terms of the partnership agreement. Ownership interest in the project is final with 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal has received a $6.2 million cash distribution from the partnership.

Under the terms of the DOE loan agreement, project profits are distributed to the equity partners semi-annually (February and August), following Final Completion, which was achieved on August 1, 2013. U.S. Geothermal’s share of this first distribution received March 5, 2014 was $4.6 million, out of a total distribution to the partners of $7.7 million, which represents profits generated from the project since initial operation began in November 2012.

Under the Loan Guarantee Agreement at Neal Hot Springs with the Department of Energy, all funds for USG Oregon LLC are deposited into PNC Bank subject to certain procedural restrictions on the use of the funds. The waterfall of funds out of the Revenue account is processed semi-annually. At September 30, 2014, $16.7 million in USG Oregon LLC funds were deposited at PNC Bank, and were unavailable for immediate corporate needs.

For projects under construction before the end of 2010 and online before the end of 2013, a project was eligible to take a 30% investment tax credit (“ITC”) in lieu of the production tax credit (“PTC”). The ITC was able to be converted into a cash grant within the first 90 days of operation of the plant. Phase I at San Emidio attained commercial operation on May 25, 2012. An application was submitted in July 2012 electing to take the ITC cash grant in lieu of the PTC. The United States Department of Treasury notified the Company that it would allow $10.65 million in cash grant. The cash grant proceeds were received on November 10, 2012 and used to repay the Ares Capital bridge loan facility, with the remaining balance payable to USG Nevada LLC. An additional $1.05 million of cash grant items were subsequently approved and paid in March 2013. For the Neal Hot Springs project, an application was submitted in the first quarter 2013 electing to take the ITC cash grant, in lieu of the PTC, for approximately $35.9 million from U.S. Treasury and the funds would be used to fund reserves required under the DOE Loan Guarantee Agreement and return funds to our partner in the project, Enbridge. Due to federal sequestration in early 2013, the ITC cash grant amount received in April 2013 was reduced by 8.7% to $32.7 million.

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In July 2010, the Company applied to the Oregon Department of Energy for the Business Energy Tax Credit (“BETC”), which allows an income tax credit for up to $20 million in qualifying expenditures for a renewable energy project. The Neal Hot Springs project completed final certification for the credit and sold it to a pass-through partner, monetized at a cash value of $7.36 million (less a broker fee) in November 2013.

On May 21, 2012, the Company entered into a purchase agreement (the “Purchase Agreement”) with Lincoln Park Capital Fund, LLC (“LPC”), pursuant to which the Company has the right to sell to LPC up to $10,750,000 in shares of the Company’s common stock, (“Common Stock”), subject to certain limitations and conditions set forth in the Purchase Agreement and imposed by the Company’s board of directors and pricing committee thereof. Pursuant to the Purchase Agreement LPC initially purchased $750,000 in shares of Common Stock at $0.38 per share. Following this initial purchase, on any business day and as often as every other business day over the 36-month term of the Purchase Agreement, and up to an aggregate amount of an additional $10,000,000 (subject to certain limitations) in shares of Common Stock, the Company has the right, from time to time, at its sole discretion and subject to certain conditions to direct LPC to purchase up to 250,000 shares of Common Stock, which amount may be increased in accordance with the Purchase Agreement if the closing sale price of Common Stock on the NYSE MKT exceeds certain specified levels. The purchase price of shares of Common Stock pursuant to the Purchase Agreement will be based on prevailing market prices of Common Stock at the time of sales without any fixed discount, and the Company will control the timing and amount of any sales of Common Stock to LPC. No sales of Common Stock under the Purchase Agreement will be made through the TSX. The Purchase Agreement contains customary representations, warranties and agreements of the Company and LPC, limitations and conditions to completing future sale transactions, indemnification rights and other obligations of the parties. There is no upper limit on the price per share that LPC could be obligated to pay for Common Stock under the Purchase Agreement. LPC shall not have the right or the obligation to purchase any shares of Common Stock if the purchase price of those shares, determined as set forth in the Purchase Agreement, would be below $0.25 per share. The Company has the right to terminate the Purchase Agreement at any time, at no cost or penalty. Actual sales of shares of Common Stock to LPC under the Purchase Agreement will depend on a variety of factors to be determined by the Company from time to time, including (among others) market conditions, the trading price of the Common Stock and determinations by the Company as to available and appropriate sources of funding for the Company and its operations. As consideration for entering into the Purchase Agreement, the Company has issued to LPC 651,819 shares of Common Stock. The Company will not receive any cash proceeds from the issuance of these 651,819 shares. As of September 30, 2014, the Company has sold LPC an aggregate of 4,625,506 shares of common stock pursuant to the Purchase Agreement for net proceeds of approximately $1,343,639 (net of $86,911 broker and legal fees). On December 21, 2012, the Company and LPC entered into an Amendment No. 1 to the Purchase Agreement (the “Amendment”) to reduce the total amount that can be purchased under the Purchase Agreement, including amounts already purchased, from $10,750,000 to $6,500,000.

In September 2010, Oregon USG Holdings, LLC (a wholly owned subsidiary) entered into agreements with Enbridge (U.S.) Inc. that formed a strategic and financial partnership to finance the Neal Hot Springs project located in eastern Oregon. A component of these agreements included a $5 million convertible promissory note, which converted. The DOE guaranteed project loan was treated as an equity contribution by Enbridge to the project. The agreements also provided for additional equity contributions of $13.8 million from Enbridge that when combined with the $5 million convertible promissory note earned Enbridge a 20% direct ownership in the project. As a result of cost overruns for the project, and at the election of the Company, an additional payment obligation of up to $8 million was contributed by Enbridge that increased their direct ownership in the project by 1.5 percentage points for each $1 million contributed. Added to their base 20% ownership, additional payments increased Enbridge’s ownership to 27.5%. An additional $6 million cost overrun facility was established by Enbridge to cover costs that resulted from unexpected poor results from injection well drilling. The additional investment by Enbridge increased their ownership in USG Oregon LLC based on running a project financial model and determining what percentage of the forecasted project income would be allocated to Enbridge to arrive at a predetermined rate of return for the additional investment. In February 2014, the final ownership interest in the Neal Hot Springs project was determined to be 60% for U.S. Geothermal and 40% for Enbridge. As a result of the final agreement, U.S. Geothermal Inc. received an approximate $6.2 million cash distribution from the partnership.

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Potential Acquisitions and Acquisitions Completed Subsequent to Period End

The Company intends to continue its growth through the acquisition of ownership or leasehold interests in properties and/or property rights that it believes will add to the value of the Company’s geothermal resources, and through possible mergers with or acquisitions of operating power plants and geothermal or other renewable energy properties. The following planned merger was in process at the end of the current reporting period:

Earth Power Resources (“EPR”) Merger
On October 16, 2014, the Company announced the signing of an Agreement and Plan of Merger with EPR. Under the terms of the Agreement, the EPR shareholders will receive a total of 692,700 shares of U.S. Geothermal Inc. stock in exchange for all outstanding shares of EPR stock. The transaction is expected to be completed by the end of November 2014 following EPR shareholder approval. Acquired assets include geothermal leases covering 26,017 acres in the State of Nevada representing three projects.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been made. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for the financial statements.

See Management’s Discussion and Analysis and the financial statements and related footnotes included in our Transition Report on Form 10-K for the year ended December 31, 2013, for a description of our critical accounting policies.

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

Interest Risk on Investments
At September 30, 2014, the Company held investments of $27,448,313 in money market accounts. These are highly liquid investments that are subject to risks associated with changes in interest rates. The money market funds are invested in governmental obligations with minimal fluctuations in interest rates and fixed terms.

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Foreign Currency Risk
The Company is subject to a limited amount of foreign currency risks associated with cash deposits maintained in Canadian currency. The Company has utilized and it is continuing to utilize the Canadian markets for raising capital. By proper timing of the transactions and then maintenance of adequate operating funds in other financial resources, the Company has been able to mitigate some of the risks surrounding foreign currency exchanges. At the quarter ended September 30, 2014, the Company held deposits that amounted to less than $10,000 in U.S. dollar equivalents. As a matter of standard operating practice, the Company does not maintain large balances of Canadian currency, and substantially all operating transactions are conducted in U.S. dollars.

Prior to April 1, 2007, the strike price for the Company’s stock option plan had been stated in Canadian dollars as the plan had been administered through our Vancouver office and Pacific Corporate Trust Company. This subjected the Company to foreign currency risk in addition to the normal market risks associated with the stock price fluctuations. A long-term liability had been established to reflect the fair value of the stock options payable. The strike price on subsequent option grants is stated in U.S. dollars.

Commodity Price Risk
The Company is exposed to risks surrounding the volatility of energy prices. These risks are impacted by various circumstances surrounding the energy production from natural gas, nuclear, hydro, solar, coal and oil. The Company has been able to mitigate, to a certain extent, this risk by signing power purchase contracts that exceed 20 year periods for the power plants currently in production and scheduled to go into production. This type of arrangement will be the model for power purchase contracts planned for future power plants.

Item 4 - Controls and Procedures

An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this report. Based on that evaluation, our management, including the CEO and CFO, concluded that our disclosure controls and procedures were effective at the end of this period covered by this report to ensure that information we are required to disclose in the reports that we file or submit under the Securities Exchange Act of 1934, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms relating to us, including our consolidated subsidiaries, and was accumulated and communicated to our management, including our CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change to our internal control over financial reporting during the nine months ended September 30, 2014 that has materially affected, or is likely to materially affect, our internal control over financial reporting.

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PART II- OTHER INFORMATION

Item 1 - Legal Proceedings

None.

Item 1A - Risk Factors

See “Risk Factors” in our transition report on Form 10-K for the year ended December 31, 2013. There have been no material changes in the risk factors during the nine months ended September 30, 2014.

Item 2 - Unregistered Sales Of Equity Securities And Use Of Proceeds

None.

Item 3 – Defaults Upon Senior Securities

None.

Item 4 – Mine Safety Disclosures

Not applicable.

Item 5 - Other Information

None.

Item 6 - Exhibits

See the exhibit index to this quarterly report on Form 10-Q.


SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

  U.S. GEOTHERMAL INC.
  (Registrant)
   
Date: November 13, 2014 By: /s/ Dennis J. Gilles
  Dennis J. Gilles
  Chief Executive Officer
   
Date: November 13, 2014  
  By: /s/ Kerry D. Hawkley
  Kerry D. Hawkley
  Chief Financial Officer and Corporate Secretary

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EXHIBIT INDEX

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Exhibit 31.1

CERTIFICATION

I, Dennis J. Gilles, certify that:

  1.

I have reviewed this report on Form 10-Q of U.S. Geothermal Inc.;

       
  2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

       
  3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

       
  4.

The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

       
  a.

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

       
  b.

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

       
  c.

evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

       
  d.

disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

       
  5.

The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

       
  a.

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and




  b.

any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 13, 2014

/s/ Dennis J. Gilles
Dennis J. Gilles
Chief Executive Officer





Exhibit 31.2

CERTIFICATION

I, Kerry D. Hawkley, certify that:

  1.

I have reviewed this report on Form 10-Q of U.S. Geothermal Inc.;

       
  2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

       
  3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

       
  4.

The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

       
  a.

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

       
  b.

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

       
  c.

evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

       
  d.

disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

       
  5.

The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

       
  a.

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and




  b.

any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: November 13, 2014

/s/ Kerry D. Hawkley
Kerry D. Hawkley
Chief Financial Officer





Exhibit 32.1

CERTIFICATION

In connection with the quarterly report of U.S. Geothermal Inc. (the “Registrant”) on Form 10-Q for the period ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Dennis J. Gilles, Chief Executive Officer of the Registrant, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

  1.

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

     
  2.

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

 

Date: November 13, 2014

 

/s/ Dennis J. Gilles  
Dennis J. Gilles  
Chief Executive Officer  





Exhibit 32.2

CERTIFICATION

In connection with the quarterly report of U.S. Geothermal Inc. (the “Registrant”) on Form 10-Q for the period ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kerry D. Hawkley, Chief Financial Officer of the Registrant certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to my knowledge:

  1.

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

     
  2.

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

 

Date: November 13, 2014

 

/s/ Kerry D. Hawkley
Kerry D. Hawkley
Chief Financial Officer


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